1 6560 - 50 - P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 51, 52, 72, 78, and 97 [EPA-HQ-OAR- 2009 - 0491; FRL -xxxx-x]

RIN 2060 -AP50 Federal Implementation Plans to Reduce Interstate Transport of

Fine Particulate Matter and Ozone AGENCY: Environmental Protect ion Agency (EPA). ACTION: Proposed rule. SUMMARY: EPA is proposing to limit the inters tate transport of emissions of n itrogen oxides (NO X ) and sulfur dioxide (SO 2 ) . In this action, EPA is proposing to both identify and limit emissions within 32 states i n the eastern United States that affect the ability of downwind states to attain and maintain compliance with the 1997 and 2006 fine particulate matter ( PM2.5 ) national ambient air quality standards ( NAAQS ) and the 1997 ozone NAAQS . E PA is proposing to limit these emissions through Federal Implementation Plans ( FIPs) that regulate electric generating units (EGUs) in the 32 states. This action will substantially reduce the impact of transported emissions on downwind states. In conjunction with other feder al and state actions , it helps assure that all but a handful of areas in the eastern part of the country will be in compliance with the current ozone and PM2.5 NAAQS by 2014 or earlier. To the extent2

the proposed FIP s do not fully address all significant transport, EPA is committed to assur ing that any additional reductions needed are addressed quickly. DATES: Comments . Comments must be received on or before [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] . Public Hearing : Publ ic hearings will be held on [ ADD THE THREE DATES; MAKE SURE A FEW DAYS APART FOR EACH] in [ADD THE THREE LOCATIONS] . Please refer to SUPPLEMENTARY INFORMATION for additional information on the comment period and the public hearing. ADDRESSES : Submit your comments, identified by Docket ID No. EPA- HQ - OAR- 2009
- 0491 by one of the following methods:

 www.regulations.gov . Follow the on line instructions for submitting comments. Attention Docket ID No. EPA
- HQ - OAR2009
- 0 491.

 E -mail: a - and
- r - docket@epa.gov . Attention Docket ID No. EPA- HQ - OAR- 2009
- 0491.

 Fax: ( 202 ) 566
- 9744 . Attention Docket ID No. EPA
- HQ - OAR2009
- 0491.

 Mail: EPA Docket Center, EPA West (Air Docket), Attention Docket ID No. EPA
- HQ - OAR- 2009
- 0491 , U.S. Environmental Protection Agency, Mailcode: 2822T , 1200 Pennsylvania Avenue, NW, Washington, DC 20460. Please include 2 copies.3

In addition, please mail a copy of your comments on the information collection provi sions to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17th Street, NW, Washington, DC 20503.

 Hand Delivery: U.S. Environmental Protection Agency, EPA West (Air Docket), 1301 Con stitution Avenue, Northwest, Room 3334 , Washington, DC 20004, Attention Docket ID No. EPA- HQ - OAR- 2009
- 0491 . Such deliveries are only accepted during the Docket ' s normal hours of operation, and special arrangements should be made for deliveries of boxed in formation. Instructions . Direct your comments to Docket ID No. EPA
- HQ - OAR2009
- 0491 . EPA ' s policy is that all comments received will be included in the public docket without change and may be made available online at www.regulations.gov , including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or e -mail. The www.regulations.gov Website is an " anonymous access " system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment.4

If you send an e
-mail comment directly to EPA without going through www.regulations.gov , your e -mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD
- ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of
s pecial characters, avoid any form of encryption, and be free of any defects or viruses. For additional information about EPA ' s public docket , visit the EPA Docket Center homepage at www.epa.gov/epahome/ dockets.htm . Docket . All documents in the docket are listed in the www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g. , CBI or other information whose dis closure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in
www .regulations.gov or in hard copy at the Air and Radiation Docket and Information Center, EPA/DC, EPA West Building, Room 3334 , 1301 Constitution Ave., NW, Washington, DC. The Public5

Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566
- 1744, and the telephone number for the Air Docket is (202) 566
- 1742. FOR FURTHER INFORMATION CONTACT: Mr. Tim Smith , Air Quality Policy Division, Office of Air Qual ity Planning and Standards (C539
- 04), Environmental Protection Agency, Research Triangle Park, NC 27711 ; telephone number: (919) 541
- 4718 ; fax number: (919) 541
- 0824; e -mail address: smith.tim@epa.gov . For legal questions, please contact Ms. Sonja Rodman, U.S. EPA, Office of General Counsel, Mail Code 2344A, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202)564
- 4079 ; e -mail address rodman.sonja@epa.gov . SUPPLEMENTARY INFORMATION: I. Preamble Glossary of Terms and Abbreviations The following are abbreviations of terms used in the preamble. [NEEDS TO BE UPDATED] CAA or Act Clean Air Act CAIR Clean Air Interstate Rule CBI Confidential Business Information EGU Electric Generating Un it FGD Flue Gas Desulfurization FIP Federal Implementation Plan EPA U.S. Environmental Protection Agency IPM Integrated Planning Model lb/mmbtu Pounds Per Million British Thermal Unit μ g/m3 Micrograms Per Cubic Meter NAAQS Na tional Ambient Air Quality Standard s NO x Nitrogen Oxide s SNCR Selective Non
- catalytic Reduction6

SCR Selective Catalytic Reduction SIP State Implementation Plan PM2.5 Fine Particulate Matter, Less Than 2.5

Micrometers PM 10 Fine and C oarse P articulate Matter, Less than 10

Micrometers PM Particulate Matter RIA Regulatory Impact Analysis SO 2 Sulfur Dioxide SOX Sulfur Oxides, I ncluding Sulfur Dioxide (SO 2 ) and

Sulfur Trioxide (SO 3 ) TIP Tribal Implementation Plan tpy Tons Per Year TSD Technical Support Document II. General Information A. Does this action apply to me? This rule affects EGUs, and regulates the following groups: Industry Group NAICS a Utilities (electric, natural gas, other systems)
..........................................

.............. 2211 , 2212, 2213

a North American Industry Classification System. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is aware of that could potentially be regulated. Other types of entities not listed in the table could also be regulated. To determine whether your facility would be regulated by the proposed rule, you should carefully examine the applicability criteria in proposed §§ 97.404, 97.504, 97,604, and 97.704 .7

B. Where can I get a copy of this document and other related information? In addition to being available in the docket, an electronic copy of this proposal will also be available on the World Wide Web. Fo llowing signature by the EPA Administrator, a copy of this action will be posted on the transport rule website www.epa.gov/airtransport . C. What should I consider as I prepare my comments for EPA? 1. Submitting CBI . Do not submit this information to EPA through www.regulations.gov or e -mail. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404
- 02), U.S. EPA, Research Triangle Park, NC 27711, Attention Docket ID No. EPA
- HQ - OAR- 2009
- 0491 .8

2. Tips for preparing your comments . When s ubmitting comments, remember to:

 Identify the rulemaking by docket number and other identifying information (subject heading, Federal Register date and page number).

 Follow directions
- The agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.

 Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.

 Describe any assumptions and provide any technical information and /or data that you used.

 If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.

 Provide specific examples to illustrate your concerns, and suggest alternatives.

 Explain you r views as clearly as possible, avoiding the use of profanity or personal threats.

 Make sure to submit your comments by the comment period deadline identified. D. How can I find information about the public hearing s ? The EPA will hold 3 public hearing s on this proposal on9

[ADD THE THREE DATES] . The hearing s will be held at the following location( s ): [ADD THE THREE LOCATION S ADDRESSES AND PHONE NUMBERS] . The public hearing s will begin at 9 a.m. and continue until 5 p.m., or later if necessary depending on the number of speakers. Oral testimony will be limited to 5 minutes per commenter. The EPA encourages commenters to provide written versions of their oral testimonies either electronically or in paper copy. Verbatim transcripts and written statements w ill be included in the rulemaking docket. If you would like to present oral testimony at 1 of the hearing s , please notify Ms. Pamela S. Long, Air Quality Policy Division (C504
- 03), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541
- 064 1 ; e mail: long.pam@epa.gov . Persons interested in presenting oral testimony should notify Ms. Long at least 2 days in advance of the public hearing s . For updates and additional information on the public hearing s, please check EPA’s website for this rulemaking, www.epa.gov/airtransport . The public hearing s will provide interested parties the opportunity to present data, views, or arguments concerning the proposed rule. The EPA officials may ask clarifying questions during the oral presentations, but wil l not respond to the presentations or comments at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as any oral comments and10

supporting information presented at the public hearing s . E. How is this Preamble Organized? I. Preamble Glossary of Terms and Abbreviations II. General Information A. Does this action apply to me? B. Where can I get a copy of this document and other related information? C. What should I consider as I prepare my comments for EPA? D. How can I find information about the hearings ? E. How is the preamble organized? III. Summary of P roposed Rule and B ackground A . Summary of P roposed Rule B. Background 1. What is the source of EPA’s authority for this a ction? 2. What air quality problems does this proposal address? 3. Which NAAQS does this proposal address? 4. EPA T ransport Rulemaking H istory C. What are the goals of this proposed rule? 1. Primary Goals 2. Key Guiding P rinciples D. Why does this prop osed rule focus on the eastern half of the United States ? E. Anticipated Rules Affecting Power Sector IV. Defining “ S ignificant C ontribution” and “ I nterference With Maintenance” A. Background 1. Approach Used in NOX SIP Call and CAIR 2. Judicial Opini ons 3. Overview of P roposed Approach B. Overview of Approach to I dentify C ontributing Upwind S tates 1. Background 2. Approach for P roposed Rule C. Air Quality Model ing Approach and Results 1. What a ir quality modeling p latform did EPA u se? 2. How did E PA p roject future n onattainment and maintenance for annual PM2.5 , 24
- Hour PM2.5 , and 8
- h our o zone? 3. How did EPA a ssess i nterstate c ontributions to n onattainment and maintenance? 4. What a re the e stimated i nterstate c ontributions to annual PM2.5 , 24
- h ou r PM2.5 , and 8
- h our o zone n onattainment and maintenance? D. Proposed Methodology to Quantify Emissions that Significantly Contribute or Interfere With Maintenance11

1. Explanation of Proposed Approach to Quantify Significant Contribution 2. Application 3. Discussion of Control Costs for Sources Other than EGUs E. State Emissions Budgets 1. Defining SO 2 and Annual NO X S tate Emissions Budgets for EGUs 2. Defining O zone S eason NO X S tate Emissions Budgets for EGUs F. Emissions Reduction Requirements Includin g Variability 1. Variability 2. State Budgets w ith Variability L imits 3. Summary of Emissions Reductions Across All C overed S tates G. How the P roposed Approach is C onsistent w ith Judicial Opinions I nterpreting S ection 110 (a)(2)(D)(i)(I) of the Clean Air Act H. Alternative Approaches Evaluated But Not P roposed V. Proposed Emissions C ontrol Requirements A. Pollutants I ncluded in this P roposal B. Source C ategories 1. Propose to C ontrol P ower S ector Emissions 2. Other S ource C ategories a re n ot I ncluded C. Timing of Proposed Emissions Reduction Requirements 1. Date for Prohibiting Emissions That Significant Contribute or Interfere with Maintenance of the PM2.5 NAAQS 2. Date for Prohibiting Emissions That Significant Contribute or Interfere w ith Maintenan ce of the 1997 ozone NAAQS 3. Reductions Required by 2012 to E nsure that S ignificant C ontribution and I nterference With Maintenance are E liminated as E xpeditiously as P racticable 4. How C ompliance Deadlines Address the Court’s C oncern About T iming 5. EPA Will C onsider Additional Reductions in P ollution T ransport to Assist in Meeting Any Revised or New NAAQS D. Implementing Emission Reduction Requirements 1. Approach T aken in NO X SIP Call and CAIR 2. Judicial Opinions 3. Remedy Options Overview 4. State Budgets/Limit ed Trading Proposed Remedy 5. State Budgets/Intrastate Trading Remedy Option 6. Di rect Control Remedy Option E. Projected Costs and Emissions for Each Remedy Option 1. State Budgets/Limited Trading 2. State Budgets/Intrastate T rading 3. Direct C ontrol12

4. State
- level Emissions P rojections F. Transition from the CAIR C ap - and
- trade P rograms to P roposed P rograms 1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs 2. Change in States Covered 3. Applicability, CAIR Opt
- ins and NO X SIP Call Unit s 4. Early Reduction Provisions 5 . Source Monitoring and Reporting G. Interactions With E xisting Title IV Program and NO X SIP Call 1. Title IV Interactions 2. NOX SIP Call Interactions VI. Stakeholder Outreach VII. State Implementation Plan Submissions A. Section 110 (a)(2)(D)(i) SIPs for the 1997 Ozone and PM2.5 NAAQS B. Section 110 (a)(2)(D)(i) SIPs for the 2006 PM2.5 NAAQS C. Transport Rule SIPs VIII. Title V Permitting IX. What benefits are projected for the proposed rule? A. The Impacts on PM2.5 and Ozone of the Proposed SO 2 and NOX Strategy B. Human Health Benefit Analysis C. Quantified and Monetized Visibility Benefits D. Benefits of Reducing GHG Emission E . Total Monetized Benefits F . How do the b enefits c ompare to the c osts of this p roposed rule? G . What a re the unquantified and unmonetized b enefits of the t ransport rule emissions r eductions? 1. What a re the b enefits of r educed deposition of s ulfur and n itrogen to a quatic, f orest, and c oastal e cosystems? 2. Ozone Vegetation E ffects 3. Other Health or Welfare Disbenefits of the Transport Rule that Have Not Been Quantified X. Economic impacts XI. Incorporating End
- use Energy Efficiency I nto the Proposed Transport Rule A. Background 1. What is end
- use energy efficiency? 2. How does energy effic iency contribute to cost
- effective reductions of air emissions from EGUs? 3. How does the proposed rule support greater investment in energy efficiency? 4. How EPA and states have previously integrated energy efficiency into air regulatory programs?13

B. Inc orporating End
- use Energy Efficiency into the Transport Rule 1. Options That C ould be U sed to I ncorporate E nergy E fficiency into Allowance B ased P rograms 2. Why EPA did not propose these options? XII. Statutory and Executive Order Reviews A. Executive O rder 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children F rom Environmental Health and Safety Risks H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer Advancement Act J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low
Income Populations 1. Consideration of Environmental Justice Issues in the Rule Development Process 2. Potential Environmental and Public Health Impact s to Vulnerable Populations 3. Meaningful Public Participation 4. Determination III. Summary of Proposed Rule and Background A. Summary of P roposed Rule CAA section 110(a)(2)(D)(i)(I) requires states to prohibit emissions that contribute significantly t o nonattainment in, or interfere with maintenance by, any other state with respect to any primary or secondary NAAQS. In this notice, EPA proposes to find that emissions of SO 2 and NOX in 32 eastern states contribute significantly to nonattainment or inte rfere with maintenance in one or more downwind states with respect to one or more of three air quality standards
-- the annual average14

PM2.5 NAAQS promulgated in 1997, the 24
- hour average PM2.5 NAAQS promulgated in 2006, and the ozone NAAQS promulgated in 1997. 1 These emissions are transported downwind either as SO 2 and NOX or, after transformation in the atmosphere, as fine particles or ozone. This notice identifies emission reduction responsibilities of upwind states, and also proposes enforceable FIPs to achieve the required emissions reductions in each state through cost
- effective and flexible requirements for power plants. Each state will have the option of replacing these federal rules with state rules to achieve the required amount of emissions reductions from sources selected by the state. With respect to the annual average PM2.5 NAAQS, this proposal finds that 24 eastern states have SO 2 and NO x emission reduction responsibilities, and quantifies each state’s full emission reduction responsibility under section 110(a)(2)(D)(i)(I). With respect to the 24
- hour average PM2.5 NAAQS, this proposal finds that 25 eastern states have emission reduction responsibilities. The proposed reductions will at least partly eliminate, and subject to further analysi s may fully eliminate, these states’ significant contribution and interference with maintenance for purposes of the 24
- hour average PM2.5 standard. In all, emissions reductions related to
1 In the c ontext of the jurisdictions covered by this proposed rule, EPA uses the term “states” to include the District of Columbia.15

interstate transport of fine particles would be required in 28 stat es. With respect to the 1997 ozone NAAQS, this proposal requires emissions reductions in 26 states. For 16 of these states, we propose that the required reductions represent their full significant contribution and interference with maintenance for the ozo ne NAAQS. For an additional 10 states, the required NO x reductions are needed for these states to make measurable progress towards eliminating their significant contribution and interference with maintenance. EPA has begun to conduct additional informati on gathering and analysis to determine the extent to which further reductions from these states may be needed to fully eliminate significant contribution and interference with maintenance with the 1997 ozone NAAQS . This proposed rule would achieve substant ial near
- term emissions reductions f rom the power sector. EPA projects that with the proposed rule, EGU SO 2 emissions would be 5.0 million tons lower, annual NO X emissions would be 700,000 tons lower, and ozone season NO X emissions would be 100,000 tons l ower in 2012, compared to baseline 2012 projections in the proposed covered states. Further, EGU SO 2 emissions would be 4.6 million tons lower, annual NO X emissions would be 700,000 tons lower, and ozone season NO X emissions would be 100,000 tons lower in 2014, compared to baseline 2014 projections (which will have dropped16

from 2012 due to other federal and state requirements, thereby lowering the 2014 baseline). See Table III.A
- 2 for projected EGU emissions with the proposed rule compared to baseline, an d Table III.A
- 3 for projected EGU emissions with the proposed rule compared to 2005 actual emissions. The reductions obtained through the Transport Rule FIPs will help all but a very few areas in the eastern part of the country come into attainment with t he 1997 PM2.5 and ozone standards and take major strides toward helping states address nonattainment with the 2006 24
- hour average PM2.5 standard. See Table III.A
- 1 for proposed list of covered states . EPA is committed to fulfilling its responsibility t o ensure that downwind states receive the relief from upwind emissions guaranteed under CAA section 110(a)(2)(D) For the 24
- hour PM2.5 standard, EPA’s air quality modeling shows that in the areas with continuing non
- attainment or maintenance problems, the remaining exceedances occur almost entirely in the winter months. The relative importance of particle species such as sulfate and nitrate, is quite different between summer and winter. EPA is moving ahead before the final rule is published to determine the extent to which this wintertime problem is caused by emissions transported from upwind states. Further study of the 24
- hour PM2.5 results could lead to a number of possible outcomes; EPA cannot judge the relative likelihood of17

these outcomes at this t ime. To the extent possible, EPA plans to finalize this rule with a full determination of, and remedy for, significant contribution and interference with maintenance for the 24
- hour PM2.5 standard. To that end, EPA is expeditiously proceeding with examin ation of the residual wintertime problem. ( See full discussion in section IV.D.) In the case of ozone, EPA must determine whether further NO x reductions are warranted in certain upwind states that affect two or three areas with relatively persistent ozo ne air quality problems. To support a full significant contribution determination for these states, EPA is expeditiously conducting further analysis of NO X control costs, emissions reductions, air quality impacts, and the nature of the residual air qualit y issues. EPA’s current information indicates that considering NO x reductions beyond the cost per ton levels proposed in this rule will require analysis of reductions from source categories other than EGUs, as well as from EGUs. EPA believes that develop ing supplemental information to consider NO x sources beyond EGU s would substantially delay publication of a final rule beyond the anticipated publication of spring 2011. EPA does not believe that this effort should delay the reductions and large health be nefits associated with this proposed rule. Thus, EPA intends to proceed with additional rulemaking to address fully the residual significant contribution to nonattainment and18

interference with maintenance with the ozone standard as quickly as possible. ( See full discussion in section IV.D.) This proposed rule is the first of several EPA rules to be issued over the next 2 years that will yield substantial health and environmental benefits for the public through regulation of power plants. Fossil
- fuel
- fi red power plants contribute a large and substantial fraction of the emissions of several key air pollutants, and the agency has statutory or judicial obligations to make several regulatory determinations on power plant emissions. The Administrator in Janu ary established improved air quality as an Agency priority and announced plans to “develop a comprehensive strategy for a cleaner and more efficient power sector with strong but achievable reduction goals for SO 2 , NOX , mercury, and other air toxics.” In addition to this rule, other anticipated actions include a section 112(d) rule for electric utilities to be proposed by March 2011, potential rules to address pollution transport under revised NAAQS, revisions to new source performance standards for coal and oil
- fired utility electric generating units, and best available retrofit technology (BART) and regional haze program requirements to protect visibility. These actions, and their relationship to this rule, are discussed further in section III.E.19

Ongoing r eviews of the ozone and PM2.5 NAAQS could result in revised NAAQS. To address any new NAAQS, EPA would propose interstate transport determinations in future notices . Such proposals could require greater emissions reductions from states covered by this pr oposal and/or require reductions from states not covered by this proposal. In addition, while this action proposes to require reductions from the power sector only, it is possible that reductions from other source categories could be needed to address int erstate transport requirements related to any new NAAQS. With this proposal, EPA is also responding to the remand of the CAIR by the Court in 2008. CAIR, promulgated May 12, 2005 (70 FR 25162) requires 28 states and the District of C olumbia to adopt and submit revisions to their State Implementation Plans (SIPs) to eliminate SO 2 and NOX emissions that contribute significantly to downwind nonattainment of the PM2.5 and ozone NAAQS promulgated in July 1997. The CAIR FIPs, promulgated April 26, 2006 (71 FR 25328), regulate EGUs in the covered states and achieve the emissions reduction s requirements established by CAIR until states have approved SIPs to achieve the reductions. In July 2008, the D.C. Circuit Court found CAIR and the CAIR FIPs unlawful. North Carolina v. EPA , 531 F.3d 896 (D.C. Cir. 2008) . The Court’s original decision vacated CAIR. Id. at 929
- 30. However, the Court subsequently remanded CAIR to20

EPA without vacatur because it found that “allowing CAIR to remain in effect until it is replaced by a rule consistent with our opinion would at least temporarily preserve the environmental values covered by CAIR.” North Carolina v. EPA , 550 F.3d 1176, 1178 (D.C. Cir. 2008). The CAIR requirements are
corre ctly in place and the CAIR ’s regional control programs are operating while EPA develops replacement rules in response to the remand . As described more fully in the remainder of this preamble, the approaches used in this proposed rule to measure and address each state’s significant contribution to downwind nonattainment and interference with maintenance are guided by and consistent with the Court’s opinion in North Ca rolina v. EPA and address the flaws in CAIR identified by the Court therein. Among other th ings, t he proposal relies on detailed, bottom
- up sc ientific and technical analyses, introduces a state
- specific methodology for identifying significant contribution to nonattainment and interference with maintenance, and proposes remedy options to ensure t hat all necessary reductions are achieved in the covered states. In t his action , EPA proposes to both identify and address emissions within states in the eastern United States that significantly contribute to nonattainment or interfere with maintenance by other downwind states. As discussed in section s21

III and VII in this preamble and described in greater detail in [placeholder for cite to separate findings notice] , EPA has determined, or proposed to determine, that the 32 s tates covered by this proposal e ither have not submitted SIPs adequate to meet the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS, or that the SIP provisions currently in place are not adequate to meet those requirements. As desc ribed in section IV in this preamble, EPA is proposing a state
- specific methodology to identify specific reductions that states in the eastern United States must make to satisfy the CAA section 110(a)(2)(D)(i)(I) prohibition on emissions that significantly contribute to nonattainment or interfere with maintenance in a downwind state. The proposed methodology uses state
- specific inputs and focuses on the emissions reductions available in each individual state to address the Court’s concern that the approach used in CAIR (which identified a single level of emissions achievable by the application of highly cost effective controls in the region) was insufficiently state specific. The proposed methodology uses air quality analysis to determine whether a state’s contribution to downwind air quality problems is above specific thresholds . I f a state’s contribution does not exceed those thresholds , its contribution is found to be insignificant and it is no longer22

considered in the analysis. If a state’s contributi on exceeds those thresholds, EPA takes a second step that uses a multi
factor analysis that takes into account both air quality and cost considerations to identify the portion of a state’s contribution that is significant or that interferes with maintenanc e. Section 110(a)(2)(D) requires states to eliminate the emissions that constitute this “significant contribution” and “interference with maintenance.” This proposed methodology for determining upwind state emission reduction responsibility is designed to be applicable to current and potential future ozone and PM2.5 NAAQS. It is based on cost and air quality considerations that are common to any NAAQS, but also calls for evaluation of facts specific to a particular NAAQS. As a result, application of the methodology to a revised, more stringent NAAQS might lead to a determination that greater reductions in transported pollution from upwind states are reasonable than for a current, less stringent NAAQS. To facilitate implementation of the requirement that
s ignificant contribution and interference with maintenance be eliminated, EPA developed state emissions budgets. By tying these budgets directly to EPA’s quantification of each individual state’s significant contribution and interference with maintenance, EPA directly linked the budgets to the mandate in section 110(a)(2)(D)(i)(I), and thus addressed the Court’s23

concerns about the development of budgets for the CAIR. EPA also addressed these concerns by completely eschewing any consideration or reliance on Fuel Adjustment Factors and the existing allocation of Title IV allowances. These new emissions budgets are based on the Agency’s state -by
- state analysis of each upwind state’s significant contribution to nonattainment and interference with maintenance downwind . A state’s emissions budget is the quantity of emissions that would remain after elimination of the part of significant contribution and interference with maintenance that EPA has identified in an average year (i.e., before accounting for the inherent variability in power system operations ) . 2 EPA proposes SO 2 and NOX budgets for each state covered for the 24
- hour and/or annual average PM2.5 NAAQS. EPA proposes an ozone
season 3 NOX budget for each state cover ed for the ozone NAAQS. EPA recognize s that baseline emissions from a state can be affected by changing weather patterns, demand growth, or

2 For the 10 states discussed above for which EPA has only quantified a minimum amount of emissions reductions needed to make measur able progress towards eliminating their significant contribution and interference with maintenance with respect to the 1997 8
- hour ozone NAAQS , the emissions budget is the emissions that will remain after removal of those emissions. 3 Consistent with the approach taken by the Ozone Transport Assessment Group (OTAG), the NO X SIP call, and the CAIR, we propose to define the ozone season, for purposes of emissions reduction s requirements in this rule, as May through September. We recognize that this ozone se ason for regulatory requirements differs from the official state
- specific monitoring season .24

disruptions in electricity supply from other units. As a result, emissions could vary from year to year in a state where covered sources have installed all controls and taken all measures necessary to eliminate the state’s significant contribution and interference with maintenance . As described in detail in section IV of this preamble, EPA proposes to account for the inherent variability in power system operations through “assurance provisions” based on state variability limits which extend above the state emissions budgets . S ee section V for a detailed discussion of the assurance provisions . The small amount of variability allowed take s into account the inherent variability in baseline emissions . Section IV in this preamble describes the p roposed approach to significant contribution and interference with maintenance and the state emissions budgets and variability limits in detail. EPA is also proposing FIPs to immediately implement the emission reduction requirements identified and quantified by EPA in this action. For some covered states, these FIPs will completely satisfy the emissions reductions requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. The exception is for the 10 eastern states for which EPA has not completely quantified the total significant contribution or interference with maintenance with respect to the 1997 ozone NAAQS and the 15 states for which EPA25

has not completely quantified total significant contribution or interference with maintenance with respect to the 2006 PM2.5 NAAQS in which case the FIPs would achieve measurable progress towards implementing that requirement. The emi ssions reductions requirements (i.e., the “remedy”) that EPA is proposing to include in the FIPs responds to the Court’s concerns that EPA had not shown that the CAIR reduction requirements would get all necessary reductions “in the state” as required by s ection 110(a)(2) (D)(i)(I). The proposed FIPs i nclude assurance provisions specifically designed to ensure that no state’s emissions are allowed to exceed that specific state’s budget plus the variability limit. The proposed FIPs would regulate EGUs in t he 32 covered states. EPA is proposing to regulate these sources through a program that uses state - specific budgets and allows intrastate and limited interstate trading. EPA is also taking comment on two alternative regulatory options . All options would achieve the emission s reductions necessary to address the emissions transport requirements in section 110(a)(2)(D)(i)(I) of the CAA . The option EPA is proposing for the FIPs ( "State Budgets /Limited Trading ") would use state - specific emissions budgets and allow for intrastate and limited interstate trading. This approach would assure environmental results while providing some limited flexibility to covered sources. The approach would26

also facilitate the transition from CAIR to the Transport Rule for implementing agencies and covered sources. The first alternative remedy option for which EPA requests comment would use state - specific emissions budgets and allow intrastate trading, but pr ohibit interstate trading. The second alternative remedy option, for wh ich EPA also requests comment , would use state - specific budgets and emission rate limits. See section V for further discussion of the remedy options. The proposed remedy option and the first alternative, both of which are cap
- and
- trade approaches, would u se new allowance allocations developed on a different basis from CAIR. Allowance
a llocations , like the state budgets described previously , would be developed based on the methodology used by EPA to quantify each state’s significant contribution and interf erence with maintenance. See section IV for the proposed state budget approach and section V for proposed allowance allocation approaches. In this action, EPA proposes to require reductions in SO 2 and NOX emissions in the following 25 jurisdictions that
c ontribute significantly to nonattainment in , or interfere with maintenance by , a downwind area with respect to the 24
- hour PM2.5 NAAQS promulgated in September 2006: Alabama, Connecticut, Delaware, District of Columbia, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Massachusetts, Michigan,27

Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. EPA proposes to require reductions in SO 2 and NOX emissions in t he following 24 jurisdictions that contribute significantly to nonattainment in, or interfere with maintenance by , a downwind area with respect to the annual PM2.5 NAAQS promulgated in July 1997: Alabama, Delaware, District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and Wisconsin. EPA also proposes to require reductions in o zone season NO X emissions in the following 26 jurisdictions that contribute significantly to nonattainment in, or interfere with maintenance by , a downwind area with respect to the 1997 ozone NAAQS promulgated in July 1997: Alabama, Arkansas, Connecticut, Delaware, District of Columbia, Florida, Georgia, Illinois, Indiana, Kansas, Kentucky, Louisiana, Maryland, Michigan, Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West Vir ginia. As discussed previously , EPA also is proposing FIPs to directly regulate EGU SO 2 and/or NO X emissions in the 32 covered28

states. The proposed FIPs would require the 28 jurisdictions covered for purposes of the 24
- hour and/or annual PM2.5 NAAQS to
re duce SO 2 and NOX emissions by specified amounts. The proposed FIPs would require the 26 states covered for purposes of the ozone NAAQS to reduce ozone season NO X emissions by specified amounts. In response to the Court’s opinion in North Carolina v. EPA , EPA has coordinated the compliance deadlines for upwind states to eliminate emissions that significantly contribute to or interfere with maintenance in downwind areas with the NAAQS attainment deadlines that apply to the downwind nonattainment and mainte nance areas. EPA proposes to require that all significant contribution to nonattainment and interference with maintenance identified in this action with respect to the PM2.5 NAAQS be eliminated by 2014 and propose s an initial phase of reductions starting in 2012 (covering 2012 and 2013) to ensure that the reductions are made as expeditiously as practicable and that no backsliding from current emission s levels occurs when the requirements of the CAIR are eliminated. With respect to the 1997 ozone NAAQS, EPA proposes to require an initial phase of NOX reductions starting in 2012 to ensure that reductions are made as expeditiously as practicable. EPA has determined, that for many states, these reductions will be sufficient to eliminate their significant cont ribution with respect to the29

1997 ozone NAAQS. EPA intends to issue a subsequent proposal that would require all significant contribution and interference with maintenance be eliminated by a future date for the 1997 ozone NAAQS . See Table III .A- 1 for proposed list s of covered state . Table III.A- 1 -- Lists of Covered States for PM2.5 and 8 -Hour Ozone NAAQS

State Covered for

24 -Hour and/or Annual PM2.5 Required to Reduce SO2 and NOX Covered for

8 -Hour Ozone Required to Reduce Ozone Season NOX Alabama X X Arkansas X Connecticut X X Delaware X X District of Columbia X X Florida X X Georgia X X Illinois X X Indiana X X Iowa X Kansas X X Kentucky X X Louisiana X X Maryland X X Massachusetts X Michigan X X Minnesota X Mississippi X Missouri X Nebraska X New Jersey X X New York X X North Carolina X X Ohio X X Oklahoma X Pennsylvania X X South Carolina X X30

Tennessee X X Texas X Virginia X X West Virginia X X Wisconsin X TOTALS 28 26
As discussed previously , EPA is proposing new SO 2 and/or NO X emissions budgets for each covered state . The budgets are based on the EPA ’s state
-by
- state analysis of each upwind state’s significant contribution to nonattainment and interference with maintenance downwind , before accoun t ing for the inherent variability in power system operations. As discussed in detail in section IV, the proposed approach to significant contribution to nonattainment and interference with maintenance would group the 28 states covered for the 24
- hour and /or annual PM2.5 NAAQS in two tiers reflecting the stringency of SO 2 reductions required to eliminate that state’s significant contribution to nonattainment and interference with maintenance. There would be a stringent SO 2 tier comprising 15 states (“group 1”) and a moderate SO 2 tier comprising 13 states (“group 2”) , with uniform stringency within each tier. 4 For these same 28 states, there would be one annual NO X tier with uniform stringency of NO X reductions across all 2 8 states.

4 With regard to interstate trading, the two SO 2 stringency tiers would lead to two exclusive SO 2 trading groups. That is, states in SO 2 group 1 could not trade wi th states in SO 2 group 2.31

Similarly, for the 2 6 states covered for the ozone NAAQS there would be one ozone season NO X tier with uniform stringency across all 2 6 states. The proposed stringent SO 2 tier (“group 1”) would include Georgia, Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, New York, No rth Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. The proposed moderate SO 2 tier (“group 2”) would include Alabama, Connecticut, Delaware, District of Columbia, Florida, Kansas, Louisiana, Maryland, Massachusetts, Minnes ota, Nebraska, New Jersey, and South Carolina. As discussed previously , EPA proposes to require an initial phase of reductions starting in 2012 ( covering 2012 and 2013 ) requiring SO 2 and NOX reductions in the 28 states covered for 24
- hour and/or annual PM2.5 NAAQS . A second phase of reductions would be due in 2014, covering 2014 and thereafter. As described later , for certain states the 2014 reduction requirements would be more stringent, and for certain states would remain at the same level as the 2012 requirements. For the 15 states in the stringent SO 2 tier (“group 1”), the 2014 phase would substantially increase the SO 2 reduction requirements (i.e., these states would have smaller SO 2 emissions budgets starting in 2014), reflecting the greater reduct ions needed to eliminate the portion of significant contribution and32

interference with maintenance that EPA has identified in this proposal from these states with respect to the 24
- hour PM2.5 NAAQS. For the 13 states in the moderate SO 2 tier (“group 2”), the 2014 SO 2 emissions budgets would remain the same as the 2012 SO 2 budgets for these states. The 2014 annual NO X emissions budgets for all 28 states covered for the 24
- hour and/or annual PM2.5 NAAQS would remain the same as the 2012 annual NO X budgets. With respect to the ozone NAAQS, EPA is proposing a single phase of reductions which begins in 2012. Thus, the rule does not call for any adjustment to be made to the 2012 ozone season NOX budgets for the 26 s tates covered for the ozone NAAQS. EPA inten ds to issue a subsequent proposal that would, among other things, address whether an additional phase of NO X reductions is necessary to address all significant contribution and interference with maintenance with respect to the 1997 ozone NAAQS . While this proposal assures downwind states that they will receive relief from upwind reductions that will help them achieve the NAAQS, EPA is committed to fulfilling its obligation to assure the downwind states that they receive the full relief they are entitled to under section 110(a)(2)(D) . The Agency intends to quickly address any remaining significant contribution to nonattainment and interference with maintenance in a subsequent action that will also address a new more33

stringent ozone standard that is expected to be established by EPA later in 2010. Tables III .A- 2 and III .A- 3 show projected Transport Rule emission s reductions for EGUs in all states that EPA proposes to
cover. Table III.A- 2 – Projected SO2 and NOX EGU Emissions in Covered States With the Transport Rule 5 Compared to Base Case 6

Without Transport Rule or CAIR

(Million Tons)
2012 Base Case Emissions 2012

Transport Rule Emissions 2012

Emissions Reductions 2014

Base Case Emissions 2014

Transport Rule Emissions 2014

Emissions Reductions SO 2 8.4 3 .4 5.0 7.2 2.6 4.6 Annual NO X 2.0 1.3 0.7 2.0 1.3 0.7 Ozone Season NO X 0.7 0.6 0.1 0.7 0.6 0.1

Table III.A- 3 – Projected SO2 and NOX EGU Emissions in Covered States With the Transport Rule Compared to 2005 Actual Emissions (Million Tons) 2005 Actual Emissions 2012

Transport Rule Emissions 2012

Emissions Reductions from 2005 2014

Transport Rule Emissions 2014

Emissions Reductions from 2005
5 Projected Transport Rule emissions result from individual state budgets in the proposed approach and include some banking of allowances in 2012 and use of that bank in 2014. 6 EPA’s base case EGU emissions modeling does not as sume enforceable SO 2 or NOX reductions attributed to the Transport Rule or CAIR. In this base case, a unit with existing SO 2 or NOX control equipment, but without an enforceable federal or state control requirement, is allowed to choose its most economic approach to operation within existing Acid Rain Program requirements and may opt not to operate a control. See section IV.C.1 and the Electric Generation Modeling TSD for further information on the base case modeling.34 2005 Actual Emissions 2012

Transport Rule Emissions 2012

Emissions Reductions from 2005 2014

Transport Rule Emissions 2014

Emissions Reductions from 2005 SO 2 8.9 3.4 5.5 2.6 6.3 Annual NO X 2.7 1.3 1.4 1.3 1.4 Ozone Season NO X 0.9 0.6 0.3 0.6 0.3

In addition to the emission s reductions shown previously , EPA projects other substantial benefits, as de scribed in section IX in this preamble. Air quality modeling was used to quantify the improvement s in PM2.5 and ozone concentrations that are expected to result from the emissions reductions in 2014. The results of this modeling were used to calculate the average reduction in annual average PM2.5 , 24
- hour average PM2.5 , and 8
- hour ozone concentrations for monitoring sites in the eastern U.S. that are projected to be nonattainment in the 2014 base case. For annual PM2.5 and 24
- hour PM2.5 , the average reductions are 2.4 micrograms per cubic meter ( μg/m3 ) and 4.3 μg/m3 , respectively. The average reduction in 8
- hour ozone at monitoring sites projected to be nonattainmen t in the 2014 base case is 0.3 parts per billion ( ppb ) . The reductions in annual PM2.5 , 24
- hour PM2.5 , and ozone concentrations for individual nonattainment and/or maintenance sites are provided in section IX. Table I II .A- 4 compares projected EGU emissio ns with the Transport Rule to projected EGU emissions with CAIR.35

Table III.A- 4 – Simple Comparison of SO2 and NOX Emissions from Electric Generating Units in States in the CAIR or

Transport Rule Regions* for Each Rule

2005 2012 2014 Actual Transport

Rule CAIR** Transport Rule CAIR** SO 2 ( Million T ons) 9.5 4.1 5.1 3.3 4.6 NO X (Million T ons) Annual 2.9 1.6 1.7 1.6 1.7

Ozone Season 1.0 0.7 0.8 0.7 0.8 * Emissions totals include states covered by either the Transport Rule or CAIR. For PM2.5 (SO 2 and annual NO X ), the following 30 states are included: AL, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MN, MS, MO, NE, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI. For ozone (ozone
- season NO X ), the following 30 states are included: AL, AR, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MS, MO, NJ, NY, NC, OH, OK, PA, SC, TN, TX, VA, WV, WI. ** CAIR SO 2 totals are interpolations from emissions analysis originally done for 2010 and 2015. CAIR NOX totals are as originally projected for 201 0. This CAIR modeling represents a scenario that differed somewhat from the final CAIR (the modeling did not include a regionwide ozone season NO X cap and included PM2.5 requirements for the state of Arkansas). In addition to discussion of EPA’s prop osed regulatory approach (discussed in sections IV and V), this preamble also covers the stakeholder outreach EPA conducted (section VI), SIP submissions (section VII), permitting (section VIII), projected benefits of the proposed rule (section IX), economic impacts (section X), end
- use energy efficiency (section XI), and statutory and executive order reviews (section XII). B. Background 1. What is the source of EPA’s authority for this action ? The statutory authority for this action is provided by the36

CAA , as amended (42 U.S.C. ' 7401 et seq.). Relevant portions of the CAA include, but are not necessarily limited to, sections 110(a)(2)(D), 110(c)(1), and 301(a) (1 ). Section 110(a)(2)(D) of the CAA, often referred to as the “good neighbor” provision of the Act, requires states to prohibit certain emissions because of their impact on air quality in downwind states. Specifically, it requires all states, within 3 years of promulgation of a new or revised NAAQS, to submit SIPs that: (D) contain adequate provisi ons— (i) prohibiting, consistent with the provisions of this subchapter, any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will

— (I) contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any such national primary or secondary ambient air quality standard, or (II) interfere with measures required to be included in the applicable implementation plan for any other State under part C of thi s subchapter to prevent significant deterioration of air quality or to protect visibility. (ii) insuring compliance with the applicable requirements of sections 7426 and 7415 of this title (relating to interstate37

and international pollution abatement). 42 U.S.C. ' 7410(a)(2)(D). This proposal addresses the requirement in section 110(a)(2)(D)(i)(I) regarding the prohibition of emissions within a state that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in any other stat e. As discussed in greater detail later , EPA has previously issued two rules interpreting and clarifying the requirements of section 110(a)(2)(D)(i)(I). The NO X SIP Call, promulgated in 1998, was largely upheld by the U.S. Court of Appeals for the D.C. C ircuit in Michigan v. EPA , 213 F.3d 663 (D.C. Cir. 2000). The CAIR, promulgated in 2005, was remanded by the D.C. Circuit in North Carolina v. EPA , 531 F.3d 896 (D.C. Cir. 2008) , modified on reh’g , 550 F.3d. 1176 (D.C. Cir. 2008). These decisions provide additional guidance regarding the requirements of section 110(a)(2)(D)(i)(I) and are discussed later in this section. Section 301(a)(1) of the CAA gives the Administrator of EPA general authority to “prescribe such regulations as are necessary to carry o ut [her] functions under this chapter.” 42 U.S.C. § 7601(a)(1). Pursuant to this section, EPA has authority to clarify the applicability of CAA requirements. In this action, EPA is clarifying the applicability of section 110(a)(2)(D)(i)(I) by proposing to identify SO 2 and NOX emissions that each affected state must prohibit pursuant to that section38

with respect to the PM2.5 NAAQS promulgated in 1997 and 2006 and the 8
- hour ozone NAAQS promulgated in 1997. The improvements in air quality that would resu lt from the reductions in upwind state emissions that EPA is proposing to require would assist downwind states affected by transported pollution in developing, pursuant to section 110 of the CAA, their SIPs to provide for expeditious attainment and mainten ance of the NAAQS. Section 110(a) of the CAA assigns to each state both the primary responsibility for attaining and maintaining the NAAQS within such state, 42 U.S.C. § 7410(a)(1), and the primary responsibility for prohibiting emissions activity within the state which will significantly contribute to nonattainment or interfere with maintenance in a downwind area. 42 U.S.C. § 7410(a)(2)(D)(i)(I). States fulfill these CAA obligations through the SIP process described in section 110(a) of the Act. Sect ion 110(c)(1) of the Act, however, requires EPA to act when a state has not been able to or has not fulfilled its obligation to submit a SIP that meets the requirements of the Act. Specifically, section 110(c)(1) provides that:

The Administrator shall pr omulgate a Federal implementation plan at any time within 2 years after the Administrator

– (A) finds that a State has failed to make a required submission or finds that the plan or plan revision39

submitted by the State does not satisfy the minimum criteri a established under subsection (k)(1)(A) of this section, or (B) disapproves a State implementation plan submission in whole or part, unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administra tor promulgates such Federal implementation plan. 42 U.S.C. ' 7410(c)(1). Section 110(k)(1)(A), in turn, calls for the Administrator to establish criteria for determining whether SIP submissions are complete. 42 U.S.C. ' 7410(k)(1)(A). As discussed in g reater detail in s ection VII, for all states covered by the FIPs proposed in this action, EPA either has taken, has proposed to take, or believes it may need to take one of the following actions with respect to the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS an d/or the 2006 PM2.5 NAAQS: (1) find that the state has failed to make a SIP submission required by section 110(a)(2)(D)(i)(I) or section 110(k)(5) of the Act; (2) find that such a SIP submission is incomplete; or (3) disapprove such a SIP submission. Once EPA has taken one of the these actions, pursuant to section 110(c)(1), it has authority to promulgate a FIP directly implementing the requirements of section 110(a)(2)(D)(i)(I), provided the state has not submitted and EPA has not approved a SIP submissio n that corrects the SIP40

deficiency prior to promulgation of the FIP. 2. What air quality problems does this proposal address? a. Fine Particles Fine particles are associated with a number of serious health effects including premature mortality, aggravatio n of respiratory and cardiovascular disease (as indicated by increased hospital admissions, emergency room visits, health
related absences from school or work, and restricted activity days), lung disease, decreased lung function, asthma attacks, and certai n cardiovascular problems. See EPA, Air Quality Criteria for Particulate Matter (EPA/600/P

– 99/002bF, October 2004) at 9.2.2.3. See also integrated science assessment for the PM NAAQS review, December 2009 , http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546 . Individuals particularly sensitive to fine particle exposure include older adults, people with heart and lung disease, and children. This rule, and the NAAQS which it is related to, consider the effects of fine particles on vulnerable populations ( see further discussion in section XII.G and section XII.J of this notice). More detailed information on health effects of fine particles can be found on EPA’s Web site at: http://epa.gov/pm/standards.html . In addition to effects on public health, fine particles are linked to a number of public welfare effects. First, PM2.5 are41

the major cause of reduced visibility (haze) in parts of the United States, including many of our national parks and wilderness areas. For more information about visibility, visit EPA’s website at www.epa.gov/visibility . Second, particles can be carried over long distances by wind and then settle on ground or water. The effects of this settling include: making lakes and streams acidic; changing the nutrient balance in coastal waters and large river basins; depleting the nutrients in soil; damaging sensit ive forests and farm crops; and affecting the diversity of ecosystems. More information about these effects is available at EPA’s website at http://www.epa.gov/acidrain/effects/index.html . Finally, particle pollution can stain and damage stone and other materials, including culturally important objects such as statues and monuments. In 1997, EPA revised the NAAQS for PM to add new annual average and 24

–hour standards for fine particles, using PM2.5 as the indicator (62 FR 38652 ). These revisions es tablished an annual standard of 15 μg/m3 and a 24
- hour standard of 65 μg/m3
. During 2006, EPA revised the air quality standards for PM2.5 . The 2006 standards decreased the level of the 24
- hour fine particle standard from 65 μg/m3 to 35 μg/m3 , and retaine d the annual fine particle standard at 15 μg/m3
. In the preamble to the final rule for CAIR in May 2005, EPA42

discussed ambient monitoring for 2001
- 2003, the most recent 3
- year period available at the time. These results showed widespread exceedances of the 15 μ g/m3 annual PM2.5 standard in the eastern United States, with additional exceedances in parts of California and one county in Montana. At that time, 82 counties in the U.S. had at least one monitor that violated the 1997 annual PM2.5 standard. The PM2.5 ambient air quality monitoring for the 2006
- 2008 period (most recent available) shows significant improvements. Nonetheless, areas which continue to violate the 15 μ g/m3 annual PM2.5 standard are located across a significant portion of the easte rn half of the United States, in parts of California and one county in Arizona. Based on these nationwide data, 23 counties have at least one monitor that violates the annual PM2.5 standard. The PM2.5 ambient air quality monitoring for this same 200 6
- 2008 time period shows that areas violating the 2006 24
- hour PM2.5 standard of 35 μ g/m3 (i.e., the revised 2006 standard for 24
- hour PM2.5 ) are located across much of the eastern half of the United States, in parts of California, and in some counties in several other western states

– Alaska, Washington, Oregon, Utah, and Arizona. Based on these nationwide data, 52 counties have at least one monitor that violates the 24
- hour PM2.5 standard. EPA believes that a great deal of the improvement in PM2.543

annua l and 24
- hour concentrations in the eastern U.S. can be attributed to EGU SO 2 reductions achieved due to the CAIR. While the CAIR requirements related to SO 2 did not begin until 2010, many actions were taken by EGU owners and operators in anticipation of those requirements. Emissions of SO 2 from EGUs covered by the CAIR that were also in the acid rain program (under CAA Title IV) tracking system decreased from 10.2 million tons in 2005 to 7.6 million tons in 2008 . Almost all of these emissions reductions were achieved in the areas of the Eastern United States covered by the CAIR. See http://www.epa.gov/airmarkt/progress/ARP_4.html . EPA believes that there would be substantially more nonatt ainment counties for both the annual and 24
- hour standards if the CAIR were not in effect. As required by the CAA, and in response to litigation over the 2006 standards, EPA is currently conducting a review of the 2006 PM2.5 standards. Information and documents related to this review are available at: http://epa.gov/ttn/naaqs/standards/pm/s_pm_index.html . EPA expects to complete this review and to publish any revised standards tha t may result from the review by July 2011. EPA is planning to propose the revised standards by December 2010. b. Ozone Short
- term (1
- to 3
- hour) and prolonged (6
- to 8
- hour)44

exposures to ambient ozone have been linked to a number of adverse health effec ts. At sufficient concentrations, short
term exposure to ozone can irritate the respiratory system, causing coughing, throat irritation, and chest pain. Ozone can reduce lung function and make it more difficult to breathe deeply. Breathing may become mo re rapid and shallow than normal, thereby limiting a person’s normal activity. Ozone also can aggravate asthma, leading to more asthma attacks that may require a doctor’s attention and the use of additional medication. Increased hospital admissions and emergency room visits for respiratory problems have been associated with ambient ozone exposures. Longer
- term ozone exposure can inflame and damage the lining of the lungs, which may lead to permanent changes in lung tissue and irreversible reductions in l ung function. A lower quality of life may result if the inflammation occurs repeatedly over a long time period (such as months, years, or a lifetime). There is also recent epidemiological evidence indicating that there is a correlation between short
- term ozone exposure and premature mortality. People who are particularly susceptible to the effects of ozone include people with respiratory diseases, such as asthma. Those who are exposed to higher levels of ozone include adults and children who are active o utdoors. This rule, and the NAAQS which it is related to, consider the effects of ozone on45

vulnerable populations ( see further discussion in section XII.G and section XII.J of this notice). In addition to causing adverse health effects, ozone affects vegetation and ecosystems, leading to reductions in agricultural crop and commercial forest yields; reduced growth and survivability of tree seedlings; and increased plant susceptibility to disease, pests, and other environmental stresses (e.g., harsh weather). In long
- lived species, these effects may become evident only after several years or even decades and have the potential for long
- term adverse impacts on forest ecosystems. Ozone damage to the foliage of trees and other plants can also decrease the a esthetic value of ornamental species used in residential landscaping, as well as the natural beauty of our national parks and recreation areas. More detailed information on effects of ozone can be found at the following EPA Web site: http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3_index.html In 1997, a t the same time we revised the PM2.5 standards, EPA issued its final action to revise the NAAQS for ozone (62 FR 38856) to estab lish new 8

–hour standards. In this action published on July 18, 1997, we promulgated identical revised primary and secondary ozone standards that specified an 8
- hour ozone standard of 0.08 parts per million (ppm). Specifically, the standards require that the 3
- year average of the fourth46

highest 24
- hour maximum 8
- hour average ozone concentration may not exceed 0.08 ppm. In general, the 8
- hour standards are more protective of public health and the environment and more stringent than the pre
- existing 1
- hour ozone standards. At the time EPA published the CAIR and the CAIR FIP rulemakings, wide geographic areas, including most of the nation’s major population centers, experienced ozone levels that violated the 1997 NAAQS of 8
- hour ozone 0.08 ppm (effectively 0 .084 ppm as a result of rounding). These areas included much of the eastern part of the United States and large areas of California. The EPA published the 8
- hour ozone attainment and nonattainment designations in the Federal Register on April 30, 2004 (6 9 FR 23858). These designations, based on ozone season monitoring data for the 2001
- 2003 time period, resulted in 112 areas designated as nonattainment. As of December 2009, significant emissions reductions have allowed 58 of the original 112 nonattainme nt areas to be re
- designated to attainment. In addition, for a number of areas still designated as nonattainment ozone monitoring data for 2006
- 2008 (most recent data available) show levels below the standard. EPA believes a number of factors contributed to NOx emissions reductions subsequent to the 2001
- 2003 time period. First, EGU emissions were substantially reduced as EGUs in the eastern U.S. came into compliance with the NO X SIP Call. A series of progress reports47

discussing the effect of the NO X SI P Call reductions can be found on EPA’s website at: http://www.epa.gov/airmarkets/progress/progress

- reports.html . Additional information on emissions and air quality trends are available in EPA’s 2007 and 2008 air quality trends reports, which are available at: http://www.epa.gov/airtrends/ . Second, mobile source emissions standards for onroad gasoline and vehicle emissions standar ds began to reduce mobile source emissions as the fleet began turning over vehicles to meet tightened NOx emissions standards. Continued improvement in ozone is expected with continued reductions in mobile source emissions. On March 12, 2008, EPA published a revision to the 8
- hour ozone standard, lowering the level from 0.08 ppm to 0.075 ppm. On September 16, 2009, EPA announced it would reconsider these 2008 ozone standards. The purpose of the reconsideration is to ensure that the ozone standards are clearly grounded in science, protect public health with an adequate margin of safety, and are sufficient to protect the environment. EPA proposed revisions to the standards on January 19, 2010 (75 FR 2938) and will issue final standards by August 31, 2010. Information on the 2008 revisions to the ozone standard, and on all subsequent activity based on the reconsideration, is available at: http://www.epa.gov/air/ozonepollution/actions.html#sep09s .48

3. Which NAAQS does this proposal address? This propo sed action addresses the requirements of CAA section 110(a)(2)(D)(i)(I) as they relate to: (1) the 1997 annual PM2.5 standards, (2) the 2006 daily PM2.5 standards, and (3) the 1997 ozone standards The original CAIR and CAIR FIP rules, which pre
- dated the 2006 standards, addressed the 1997 ozone and PM2.5 standards only. The 1997 8
- hour ozone standard is 0.08 ppm. The 1997 PM2.5 standards promulgated in 1997 established a 15 ug/3 standard for 24
- hour PM2.5 and a 65 ug/m3 standard for annual PM2.5 . In 20 06, the 24
- hour PM2.5 standard was lowered to 35 ug/m3 and the 15 ug/m3 annual PM2.5 standard was left unchanged. For this proposal, EPA fully addresses the requirements of CAA section 110(a)(2)(D)(i)(I) for the annual PM2.5 standard of 15 ug/m3 . For the 24
- hour standard of 35 ug/m3 and for the 1997 8
- hour ozone standard of 0.08 ppm, EPA fully addresses the CAA section 110(a)(2)(D)(i)(I) requirements for some states, but for the remaining states EPA will address whether further requirements are needed. This action does not address the CAA section 110(a)(2)(D)(i)(I) requirements for the revised ozone standards promulgated in 2008. These standards are currently under reconsideration. We are, however, actively conducting the49

technical analyses and other work needed to address interstate transport for the reconsidered ozone standard as soon as possible. We intend to issue as soon as possible a proposal to address the transport requirements with respect to the reconsidered standard. 4 . EPA T ransport Ru lemaking H istory
a. CAA Provisions For almost 40 years, Congress has focused major efforts on curbing ground
- level ozone. In 1970, Congress amended the CAA to require, in Title I, that EPA issue and periodically review and , if necessary , revise NAAQS for ubiquitous air pollutants ( s ections 108 and 109). Congress required the states to submit SIPs to attain and maintain those NAAQS, and Congress included, in section 110, a list of minimum requirements that SIPs must meet. Congress anticipated that areas would attain the NAAQS by 1975. In 1977, Congress amended the CAA by providing, among other things, additional time for areas that were not attaining the ozone NAAQS to do so, as well as by imposing specific SIP requirements for those nonattainment areas. These provisions first required the designation of areas as attainment, nonattainment, or unclassifiable, under section 107; and then required that SIPs for ozone nonattainment areas include the additional provisions set out in part D of Title I, as well a s50

demonstrations of attainment of the ozone NAAQS by either 1982 or 1987 ( section 172). In addition, t he 1977 Amendments included two provisions focused on interstate transport of air pollutants: the predecessor to current section 110(a)(2)(D), which requi res SIPs for all areas to constrain emissions with certain adverse downwind effects; and section 126, which, in general, authorizes a downwind state to petition EPA to impose limits directly on upwind sources found to adversely affect that state. Section 110(a)(2)(D) (i)(I) , which is key to the present action, is described in more detail later . In 1990, Congress amended the CAA to better address, among other things, continued nonattainment of the 1
- hour ozone NAAQS , the requirements that would apply if EPA revised the 1
- hour standard , and transport of air pollutants across state boundaries (Pub. L. 101
- 549, Nov. 15, 1990, 104 Stat. 2399, 42 U.S.C., 7401
- 7671q). As amended in 1990, the CAA further requires EPA to designate areas as attainment, nonattainment , and unclassifiable under a revised NAAQS ( section 107(d)(1); section 6103, Pub. L. 105
- 178). The CAA authorizes EPA to classify areas that are designated nonattainment under the new NAAQS and to establish for those areas attainment dates that are as exp editious as51

practicable, but not to exceed 10 years from the date of designation ( section 172(a)). All areas are required to submit SIPs within certain timeframes ( section 110(a)(1)), and those SIPs must include specified provisions, under section 110(a)(2 ). In addition, SIPs for nonattainment areas are generally required to include additional specified control requirements, as well as controls providing for attainment of any revised NAAQS and periodic reductions providing "reasonable further progress" in the interim ( section 172(c)). If states do not submit SIPs in a timely or approvable manner, EPA has the authority to make findings of failure to submit or impose FIPs on specific sources in the state that contribute to downwind nonattainment and interfer ence with maintenance. Significant contribution and interference with maintenance are discussed in detail in s ection IV later . The 1990 Amendments reflect general awareness by Congress that ozone is a regional, and not merely a local, problem. Ozone an d its precursors may be transported long distances across state lines, thereby exacerbating ozone problems downwind. Ozone transport is recognized as a major reason for the persistence of the ozone problem, notwithstanding the imposition of numerous contr ols, both federal and state, across the country.52

The CAA further addresses interstate transport of pollution in section 126, which Congress revised slightly in 1990. Subsection (b) of that provision authorizes each state (or political subdivision) to peti tion EPA for a finding designed to protect that entity from upwind sources of air pollutants. 7 In addition, the 1990 Amendments added section 184, which delineates a multi
- state ozone transport region (OTR) in the Northeast, requires specific additional co ntrols for all areas (not only nonattainment areas) in that region, and establishes the Ozone Transport Commission (OTC) for the purpose of recommending to EPA regionwide controls affecting all areas in that region. At the same time, Congress added sectio n 176A, which authorized the formation of transport regions for other pollutants and in other parts of the country. In September 1994, the Northeast OTC states signed a Memorandum of Understanding (MOU) committing to reduc e NO x emissions throughout the reg ion. In 1999 through 2002, most of the OTC states achieved substantial NO x reductions through an ozone season cap and trade program for NO x called the OTC NO x Budget Program, which EPA administered , and through NO X emission rate limits from certain coal p lants under Title IV . 7 In addition, section 115 authorizes EPA to require a SIP revision in certain circumstances when one or more sources within a state "cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare in a foreign country."53

Separate from activity in the OTC, EPA and the Environmental Council of the States (ECOS) formed the OTAG in 1995. This workgroup brought together interested states and other stakeholders, including industry and environmental groups. Its primary objective was to assess the ozone transport problem and develop a strategy for reducing ozone pollution throughout the eastern half of the United States . Notwithstanding significant efforts, the states generally were not able to meet the November 15, 1994 statutory deadline for the attainment demonstration and rate of progress (ROP) SIP submissions required under section 182(c). The major reason for this failure was that at that time, states with downwind nonattainment areas were not able to address transport from upwind areas. As a result, EPA recognized that development of the necessary technical information, as well as the control measures necessary to achieve the large level of reductions likely to be required, had been particularly dif ficult for the states affected by ozone transport. Accordingly, as an administrative remedial matter, EPA established new timeframes for the required SIP submittals. To allow time for states to incorporate the results of the OTAG modeling into their local plans, EPA extended the submittal date54

to April 1998. 8 The OTAG’s air quality modeling and recommendations formed the basis for what became the NO x SIP Call rulemaking and included the most comprehensive analyses of ozone transport ever conducted. The E PA participated extensively in the OTAG process that generated much useful technical and modeling information on regional ozone transport. OTAG was established to address transport issues associated with meeting the 1
- hour standard. The EPA did not promu lgate the 8
- hour standard until shortly after OTAG concluded; thus, OTAG did not recommend strategies to address the 8
- hour NAAQS. However, because EPA had proposed an 8
- hour standard, OTAG did examine the impacts of different strategies on 8
- hour average ozone predictions. They found that o zone transport caused problems for downwind areas under either the 1
- hour or 8
- hour standard. EPA's Transport SIP Call Regulatory Efforts . Shortly after OTAG began its work, EPA indicated that it intended to issue a SIP call to require states to implement the reductions necessary to address the ozone transport problem. On January 10, 1997 (62 FR 1420), EPA published a notice of intent and indicated that before taking final action, EPA would carefully consider the technical work and any recommendations of OTAG. The EPA
8 Guidance for Implementin g the 1
- hour Ozone and Pre
- Existing PM 10 NAAQS, Memorandum from Richard D. Wilson, dated December 29, 1997.55

published the NPR for the NO X SIP call by notice dated November 7, 1997 (62 FR 60319). The NPR proposed to make a finding of significant contribution due to transported NO X emissions to nonattainment o r maintenance problems downwind and to assign NO X emissions budgets for 23 jurisdictions. In light of OTAG’s work and additional information, EPA was able to assess ozone transport as it relates to the 8
- hour NAAQS and to set forth requirements as necessa ry to address the 8
- hour standard in the rulemaking. The regional reductions of NO X that would have been achieved through this SIP call for the 1
- hour NAAQS were key components for meeting the new 8
- hour ozone standard in a cost
effective manner. Therefo re, EPA believed that the OTAG recommendations for how to address ozone transport were valid for both NAAQS. The EPA published a supplemental notice of proposed rulemaking (SNPR) dated May 11, 1998 (63 FR 25902) , which proposed a model NO X budget trading p rogram and state reporting requirements and provided the air quality analyses of the proposed statewide NO X emissions budgets. Revision of the Ozone NAAQS . On July 18, 1997 (62 FR 38856), EPA issued its final action to revise the NAAQS for
ozone. The EPA’s decision to revise the standard was based on the Agency’s review of the available scientific evidence linking exposures to ambient ozone to adverse health and welfare effects56

at levels allowed by the pre
- existing 1
- hour ozone standards. The 1
- hour primary standard was replaced by an 8
- hour standard at a level of 0.08 ppm, with a form based on the 3
- year average of the annual fourth
- highest daily maximum 8
- hour average ozone concentration measured at each monitor within an area. The new primary standar d provided increased protection to the public, especially children and other at
- risk populations, against a wide range of ozone
- induced health effects. The pre
- existing 1
- hour secondary ozone standard was replaced by an 8
- hour standard identical to the n ew primary standard. The new secondary standard provide d increased protection to the public welfare against ozone
- induced effects on vegetation. Section 126 Petitions . In a separate rulemaking, EPA proposed action on petitions submitted by 8 northeastern states 9 under section 126 of the CAA. Each petition specifically requested that EPA make a finding that NO X emissions from certain major stationary sources significantly contributed to ozone nonattainment problems in the petitioning state. Both the NO X SIP call and the section 126 petitions were designed to address ozone transport through reductions in upwind NO X emissions. However, the EPA's response to the section 126 petitions

9 The 8 states were Connecticut, Massachusetts, Maine, New Hampshire, New York, Pennsylvania, Rhode Island, and Vermont.57

differed from EPA's action in the NO X SIP call rulemaking in several ways. In the NO X SIP call, EPA was determining that certain states were or would be significantly contributing to nonattainment or maintenance problems in downwind states. The EPA required the upwind states to submit SIP provisions to reduce the amounts of ea ch state’s NO X emissions that significantly contributed to downwind air quality problems. The states had the discretion to select the mix of control measures to achieve the necessary reductions. By contrast, under section 126, if findings of significant contribution were made for any sources identified in the petitions, EPA would have determined the necessary emissions limits to address the amount of significant contribution and would have directly regulated the
sources. A section 126 remedy would have applied only to sources in states named in the petitions. b. NO x SIP Call Based on the findings of OTAG, EPA proposed a rulemaking known as the NO x SIP call in 1997 and finalized it in 1998. ( See “Finding of Significant Contribution and Rulemaking for Certai n States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone; Rule,” (63 FR 57356).) This rule concluded that NO X emissions in 22 states and the District of Columbia contribute to ozone nonattainment in othe r states, and the rule required affected states to amend58

their SIPs and limit NO X emissions. EPA set an ozone season NO X budget for each affected state, essentially a cap on ozone season (summertime) NO X emissions in the state. Sources in the affected st ates were given the option to participate in a regional cap and trade program. The first control period was scheduled for the 2003 ozone season. In response to litigation over EPA’s final NO X SIP c all rule, the Court issued two decisions concerning the NOX SIP c all and its technical amendments. 10 The Court decisions, discussed later , generally upheld the NO X SIP c all and technical amendments, including EPA’s interpretation of the definition of ‘‘contribute significantly’’ under CAA section 110(a)(2)(D). The litigation over the NO X SIP c all coincided with the li tigation over the 8
- hour NAAQS. Because of the uncertainty caused by the litigation on the 8
- hour NAAQS, EPA stayed the portion of the NO X SIP c all based on the 8
- hour NAAQS (65 FR 56245, Septembe r 18, 2000). Therefore, for the most part, the Court did not address NO X SIP c all requirements under the 8
- hour ozone NAAQS. (1) What was the NO X SIP c all? The NOX SIP c all was EPA’s principal effort to reduce interstate transport of precursors for both the 1
- hour ozone
10 See Michigan v. EPA , 213 F.3d 663 (D.C. Cir. 2000), cert. denied, 532 U.S. 904 (2001) (NO X SIP call) and Appalachian Power v. EPA , 251 F.3d 1026 (D.C. Cir. 2001) (technical amendments).59

NAAQS and the 8
- hour ozone NAAQS. The EPA’s rulemaking was based on its consideration of OTAG’s recommendations, as well as information resulting from EPA’s additional work, and extensive public input generated thro ugh notice
- and
- comment rulemaking. The EPA believed that requiring NO X emissions reductions across the region in amounts achievable by uniform controls was a reasonable, cost
- effective step to take to mitigate ozone nonattainment in downwind states for bo th the 1
- hour and 8
- hour standards. It was also EPA’s goal to ensure that sufficient regional reductions were achieved to mitigate ozone transport in the eastern half of the United States and thus, in conjunction with local controls, enable nonattainment a reas to attain and maintain the ozone NAAQS. This NOX SIP c all required those jurisdictions that EPA determined significantly contribute to 1
- hour and 8
- hour ozone nonattainment problems in downwind states to revise their SIPs to include NO X control measur es to mitigate the significant ozone transport during summer months known as the “ozone season” (May
September). The EPA determined emissions reductions requirements for the covered states and source categories ( see section IV.A for a description of the approach EPA used to determine emissions reductions requirements) . The affected states were required to submit SIPs providing the specified60

amounts of emissions reductions. By eliminating these amounts of NOX emissions, the control measures would assure t hat the remaining NO X emissions would meet the level identified in the rule as the state’s NO X emissions budget and would not “significantly contribute to nonattainment, or interfere with maintenance by,” a downwind state, under section 110(a)(2)(D)(i)(I). The SIP requirements permitted each state to determine what measures to adopt to prohibit the significant amounts and hence meet the necessary emissions budget. Consistent with OTAG’s recommendations to achieve decreased NO X emissions primarily from lar ge stationary sources in a trading program, EPA encouraged states to consider electric utility and large boiler controls under a cap and trade program as a cost
- effective strategy. The EPA also recognized that promotion of energy efficiency could contribu te to a cost - effective strategy. See section V.D.1 for a discussion on the approach taken to implement the emissions reductions requirements in the NOx SIP c all. (2) Legal Challenges to the NO X SIP Call Several petitioners challenged the NOX SIP Call in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). In Michigan v. EPA , 213 F.3d 663 (D.C. Cir., 2000), cert. denied , 532 U.S. 904 (2001), the Court upheld the rule in most respects. Of greatest relevance here, the61

Co urt upheld the essential features of EPA’s approach to identifying and eliminating states’ NO X emissions that significantly contribute to downwind nonattainment. It upheld key aspects of EPA’s air quality modeling and its use of cost
effectiveness criteri a in defining states’ “significant contribution.” See id . at 673
- 79. In addition, it accepted EPA’s use of a uniform control requirement (i.e. , requiring all covered jurisdictions, regardless of amount of contribution, to reduce NOX emissions by an amoun t achievable with highly cost effective controls). See i d . at 679
- 80 . The Court , however, agreed with petitioners that certain specific applications of EPA’s approach were flawed. It thus vacated the rule with respect to Wisconsin, Missouri , and Georgia , and held that EPA had failed to provide adequate notice on two specific issues (a change in the definition of EGU and a change in control level assumed for specific sources). S ee id . at 681
- 85, 692
- 94. The Court also subsequently delayed the implementa tion date to May 31, 2004. Michigan v. EPA , 2000 WL 1341477 (D.C. Cir. 2000) . The decision resolved only issues involving the 1
- hour ozone NAAQS and did not resolve any issues involving the 8
- hour NAAQS, which provided another basis for the rule. See i d. at 670
- 71. EPA ultimately stayed the 8
- hour basis of the NO X SIP Call. See 65 FR 56245. In addition, in a subsequent case that reviewed separate EPA rulemakings making technical corrections62

to the NO X SIP Call, the D. C. Circuit remanded the case for a better explanation of EPA’s methodology for computing the growth component in the EGU heat input calculation. See Appalachian Power Co. v. EPA , 251 F.3d 1026 (D.C. Cir. 2001). More recently, the Court also rejected a challenge to a subsequent EPA rule withdrawing EPA’s findin gs of significant contribution for Georgia for the 1
- hour ozone standard. See North Carolina v. EPA , 587 F.3d 422 (D.C. Cir. 2009). (3) How the NO X Budget Trading Program (NBP) Worked The NBP was a market
-based cap and trade program created to reduce t he regional transport of emissions of NO X from power plants and other large combustion sources that contribute to ozone nonattainment in the eastern United States. Over six ozone seasons (2003
- 2008), the NBP significantly lowered NO X emissions from affect ed sources, contributing to improvements in regional air quality across the Midwest, Northeast, and Mid
Atlantic . The cap level was intended to protect public health and the environment and to sustain that protection into the future regardless of growth i n the affected sector. Ozone season NO X emissions decreased from levels in baseline years in all states participating in the NBP. (All NBP states transitioned to the CAIR NO X ozone season program in 2009 except Rhode Island.) Allowance trading was gener ally active from the start of the program in 2003. Prices and trading were down in63

2008, primarily due to uncertainty. Compliance remained virtually 100 percent throughout the program’s 6 years. Many nonattainment areas in the East saw substantial improvements in air quality concentrations that brought them in line with ozone NAAQS. The NBP, together with other federal, state, and local programs contributed to NO X reductions that have led to improvements in ozone and PM2.5 saving 580
- 1,800 lives annuall y in 2008 11 . Changes in ozone and nitrate concentrations due to the NBP have also contributed to improvements in ecosystems in the East. EPA stopped administering the NBP at the conclusion of 2008 control period activities. States still have the emissio n s reduction s requirement and could use the CAIR NO X ozone season trading program to achieve this. See section V.D.4.e. for a discussion of the results of the NOX Budget Trading Program. (4) Clean Air Interstate Rule Following promulgation of the new NAAQS in 1997 , the CAA required all state s, regardless of whether they have attainment air quality in all areas, to submit SIPs containing provisions specified under section 110(a)(2). In addition, states are required to submit SIPs for nonattainment areas whi ch are

11 U.S.EPA. September, 2009. The NOx Budget Trading Program: 2008 Environmental Results , p.964

generally required to include additional emissions controls providing for attainment of the NAAQS. As described previously , section 110(a)(2)(D) (i)(I) provides a tool for addressing the problem of transported pollution that significantly contributes to downwind nonattainment and maintenance problems. Under section 110(a)(2)(D) , a SIP must contain adequate provisions prohibiting sources in the state from emitting air pollutants in amounts that would contribute significantly to nonattainment or interf ere with maintenance in one or more downwind states. Section 110(k)(5) authorize s EPA to find that a SIP i s substantially inadequate to meet any CAA requirement. If EPA
ma ke s such a finding, it i s to require the state to submit, within a specified period , a SIP revision to correct the inadequacy (‘‘SIP call’’). In 1998, EPA used this authority to issue the NO X SIP c all, discussed previously , to require states to revise their SIPs to include measures to reduce NO X emissions that were significantly contributing to ozone nonattainment problems in downwind states. Sulfur dioxide and NO X are not the only emissions that contribute to interstate transport and PM2.5 nonattainment. However, EPA stat ed in the CAIR that it believed that , given current knowledge, i t was not appropriate to specify emission s reduction s requirements for direct PM2.5 emissions or organic65

precursors (e.g., volatile organic compounds ( VOCs ) or ammonia (NH 3 )). Similarly, for 8
- hour ozone, EPA continued to rely on the conclusion of the OTAG that analysis of interstate transport control opportunities should have focused on NO X , rather than VOCs. 12 (5) What i s the CAIR? The CAA contains a number of requirements to address nonattainment of the PM2.5 and the 8
- hour ozone NAAQS, including requir ements that states address interstate transport that significantly contributes to such nonattainment. 13 Based on air quality modeling, ambient air quality data analyses, and cost analyses, EPA found that emissions in certain upwind states resulted in amoun ts of transported PM2.5 , ozone, and their emissions precursors that significantly contributed to
no nattainment in downwind states. In the CAIR, promulgated on May 12, 2005 (70 FR 25162), EPA required SIP revisions in 2 8 states and the District of Columbia , within 18 months after publication of the notice of final rulemaking, to ensure that certain emissions of SO 2 and/or

12 The OTAG was active from 1995

– 1997 and consisted of representatives from the 37 states in that region; the District of Columbia; EPA; and interested members of the public, including industry and environmental groups. See discussion below under NO X SIP Call for further information on OTAG. 13 The term ‘‘transport’’ includes the transport of both PM2.5 and their precursor emissions and/or transport of both ozone and its precursor emissions.66

NOX -- important precursors of PM2.5 (NOX and SO 2 ) and ozone (NO X )
-

- were prohibited . Achieving the emissions reductions identif i ed, EPA concluded, would address the states’ requirements under section 110(a)(2)(D)(i)(I) of the CAA and would help PM2.5 and ozone nonattainment areas in the eastern half of the United States attain the standards . Moreover, EPA concluded that such attainment wo uld be achieved in a more certain, equitable, and cost
- effective manner than if each nonattainment area attempted to implement local emissions reductions alone , and would also assist the covered states and their neighbors in making progress toward their vi sibility goals. The CAIR built on EPA’s efforts in the NO X SIP call to address interstate pollution transport for ozone, and was EPA’s first attempt to address interstate pollution transport for PM2.5 . It required significant reductions in emissions of SO 2 and NOX , which contribute to fine particle concentrations. In addition, NO X emissions contribute to ozone problems. EGUs were found to be a major source of the SO 2 and NOX emissions which contributed to fine particle concentrations and ozone problems downwind . CAIR was designed to provide significant air quality attainment, health, and environmental improvements across the eastern U.S. in a highly cost
- effective manner by reducing SO 267

and NOX emissions from EGUs that contribute to the PM2.5 and 8
- hour ozone problems described in the rule. CAIR’s emissions reductions requirements were based on controls that EPA had determined to be highly cost
- effective for EGUs under optional cap and trade programs . However, states had the flexibility to choose the measures to adopt to achieve the specified emissions reductions. EPA required the emissions reductions to be implemented in two phases, with the first phase in 2009 and 2010 (for NOX and SO 2 , respectively), and the second phase for both pollutants in 2015. These requirements are described in more detail in section V.D.1 . In addition to promulgating findings of significant contribution to nonattainment, EPA assign ed emissions reductions requirements for SO 2 and/or NO X that each of the identified states must meet through SIP measures. Section V.D.1 discusses the approach taken in CAIR using three model multi
- state cap and trade programs for SO 2 and NOX that EPA developed and that states could choose to adopt to meet the required emissions reductions in a flex ible and cost
effective way. The requirements in the CAIR were intended to address regional interstate transport of air pollution. EPA recognized, however, that additional local reductions might be necessary to bring some areas into attainment even after significantly68

contributing upwind emissions were eliminated. 70 FR 25165
- 66, May 12, 2005 . In addition, s tates that shared an interstate nonattainment area were expected to work together in developing the nonattainment SIP for that area, reducing emissio ns that contributed to local
- scale interstate transport problems. CAIR FIPs . When EPA promulgated the final CAIR in May 2005, EPA also issued a national finding that states had failed to submit SIPs to address the requirements of CAA section 110(a)(2)(D )(i) with respect to the 1997 ozone and PM2.5 NAAQS. States were to have submitted 110(a)(2)(D)(i) SIPs for those standards by July 2000. This action triggered a 2
- year clock for EPA to issue FIP s to address interstate transport. On March 15, 2006 the E PA promulgated FIPs to ensure that the emissions reductions required by the CAIR are achieved on schedule. The FIPs did not limit states’ flexibility in meeting their CAIR requirements as all states remained free to submit SIPs at any time that, if approved by EPA, would replace the FIP for that state . As the control strategy for the FIPs, EPA adopted the model cap and trade programs that it provided in the CAIR as a control option for states, with minor changes to account for federal, rather than state, implementation. The FIPs require d power plants in affected states to participate in one or more of three separate emissions cap and trade programs that cover: (1) annual69

SO 2 emissions, (2) annual NO X emissions, and (3) ozone season NO X emissions. Emission cap and trade programs are a proven method for achieving highly cost
- effective emission s reductions while providing regulated sources with flexibility in choosing compliance strategies. The FIPs also provide d states with an option to submit abbreviated SI Ps to meet CAIR. Under this option, states c ould save the time and resources needed to develop the complete trading program SIP, while still being able to make key decisions, such as the methodology for allocating annual and/or ozone season NO X allowances . New Jersey and Delaware . Separately, on March 15, 2006, EPA issued a final rule to include Delaware and New Jersey in the CAIR to control SO 2 and NOX emissions because they contribute to PM2.5 nonattainment in other states . 71 FR 25288, April 28, 2006 . These states were already included in the CAIR because their sources contributed to nonattainment of other states’ 8
- hour ozone air quality standard. The CAIR FIP establishe d requirements for Delaware and New Jersey with respect to both ambient air qua lity standards. (6) Legal Challenges to the CAIR Petitions for review challenging various aspects of the CAIR were filed in the U.S. Court of Appeals for the D.C. Circuit. In North Carolina v. EPA , 531 F.3d 896, modified on70

reh’g 550 F.3d 1176 (D.C. Cir. 2008), the Court granted several of the petitions for review and remanded the rule to EPA for further proceedings. In its July 2008 opinion, North Carolina , 531 F.3d 896, the Court upheld several challenged aspects of EPA’s approach, but also found fatal flaws in the rule

– flaws it found significant enough to warrant vacatur of the CAIR and the associated FIPs in their entirety. In December 2008, however, the Court responded to petitions for rehearing and determined that “notwithstanding the relative flaws of CAIR, allowing the CAIR to remain in effect until it is replaced by a rule consistent with our opinion would at least temporarily preserve the environmental values covered by CAIR.” North Carolina , 550 F.3d at 1178. Accordingly, it decided to reman d the rule without vacatur “so that EPA may remedy CAIR’s flaws in accordance with [the Court’s] July 11, 2008 opinion in this case.” Id . Although the entire rule was remanded, important parts of EPA’s rulemaking were upheld by the Court in its July 2008 ruling. The Court upheld key aspects of the air quality modeling portion of EPA’s significant contribution analysis. It upheld EPA’s decision to consider upwind states for inclusion in the CAIR only if those states contributed to projected nonattainment in 2010. See North Carolina , 531 F.3d at 913
- 914. The Court further upheld the contribution threshold used in the71

air quality modeling portion of the significant contribution analysis for PM2.5 , EPA’s use of whole states as the unit of measurement, and the first
-phase NO X compliance deadline of 2009 See i d . at 914
- 17, 923
- 27, 928
- 29. The Court also found significant flaws in EPA’s approach. The Court emphasized the importance of individual state contributions to downwind nonattainment areas and held tha t EPA had failed to adequately measure significant contribution from sources within an individual state to downwind nonattainment areas in other states. Id. at 907. Further, the Court noted that EPA had not provided adequate assurance that the trading pr ograms established in the CAIR would achieve, or even make measurable progress towards achieving, the section 110(a)(2)(D)(i)(I) mandate to eliminate significant contribution. See North Carolina , 532 F.3d at 907
- 08. For these reasons, it concluded that E PA had not shown that the CAIR rule would achieve measurable progress towards satisfying the statutory mandate of section 110(a)(2)(D)(i)(I) and thus EPA lacked authority for its action. See i d . at 908. Moreover, it emphasized that where the rule constit utes a complete 110(a)(2)(D)(i)(I) remedy, it must actually require the elimination of emissions that contribute significantly to nonattainment or interfere with maintenance downwind. See i d .72

The Court further rejected the state budgets for SO 2 and NOX
which were used to implement the CAIR trading programs, finding the budgets to be insufficiently related to the 110(a)(2)(D)(i)(I) mandate of eliminating significant contribution and interference with maintenance. See i d . at 916
- 21. It also rejected EPA’s effort to harmonize the CAIR SO 2 trading program with the existing requirements of Title IV of the CAA, holding that section 110(a)(2)(D)(i)(I) did not give EPA authority to terminate or limit Title IV allowances. In addition, the Court found that EPA ha d failed to give meaning to the “interfere with maintenance” prong of section 110(a)(2)(D)(i)(I), that EPA had not demonstrated that the 2015 compliance deadline used in the CAIR was coordinated with the downwind state’s deadlines for attaining the NAAQS, and that EPA had not adequately supported its determination that sources in Minnesota significantly contributed to nonattainment or interfered with maintenance in downwind states. See i d . at 908
- 11, 911
- 13, and 926
- 28. (7) How the Clean Air Interstate Rul e Worked Building on the emissions reductions under the NBP and Acid Rain Program (ARP), CAIR was designed to permanently lower emissions of SO 2 and NOX in the eastern United States. As explained previously , although the D.C. Circuit remanded the rule to EPA, it did so without vacatur allowing the rule to73

remain in effect while EPA addresses the remand. Thus, CAIR is continuing to help states address ozone and PM2.5 nonattainment and improve visibility, reducing transported precursors of SO 2 and NOX , thr ough the implementation of three separate cap and trade compliance programs for annual NO X , ozone season NO X , and annual SO 2 emissions from power plants. See section V.D.4.e. for a discussion on CAIR implementation in 2009, the first year of the NO X annu al and ozone season programs. The CAIR annual SO 2 program began January 1, 2010. Quarterly emissions will be posted on EPA’s web site ( see http://www.epa.gov/airmarkets ) and an assessment of emissions reduction data will be available at the end of each
c ompliance period
. C. What are the goals of this proposed rule? In developing this proposed rule, EPA was guided by a number of goals and guiding principles, as discussed in this section of the preamble. 1. Primary Goals a. Respond to the Court Remand of the CAIR Most importantly, this proposal responds to the remand of the CAIR by the Court . As noted previously , the Court granted several petitions for review of the CAIR, finding fatal flaws with the rule; yet, it ultimately decided to remand the rule without vacatur to preserve the environmental benefits of the74

rule. North Carolina v. EPA , 531 F.3d 896, modified on reh’g, 550 F.3d 1176 (D.C. Cir. 2008). The action EPA is proposing would respond to the July and December 2008 opinions of the D.C. Circui t and correct the flaws in the CAIR methodology that were identified by the Court. The action responds to the Court’s concerns in numerous ways. The methodology used to measure each state’s significant contribution emphasizes air quality considerations a nd uses state specific data and information. The methodology also gives independent meaning to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I). The state budgets for SO 2 , annual NOX and ozone season NO X are directly linked to the measu rement of each state’s significant contribution and interference with maintenance. The compliance deadlines are coordinated with the attainment deadlines for the relevant NAAQS. And the proposed remedy includes assurance provisions to assure that all
nec essary reductions occur in each individual state. The action would also propose FIPs which would replace the remanded CAIR FIPs. The proposed FIPs would apply to all states covered by the rule, including those for which EPA had previously approved SIPs un der the remanded CAIR. If finalized as proposed, these FIPs would eliminate or, at a minimum, make measureable progress towards eliminating emissions of SO 2 and NOX that significantly contribute to or interfere with maintenance75

of the 1997 and 2007 PM2.5 NAAQS and the 1997 ozone NAAQS in the eastern half of the United States. b. Address T ransport Requirements With Respect to the E xisting PM2.5 S tandards This proposed rule is designed to address the requirements of section 110(a)(2)(D)(i)(I) of the CAA as they relate to the 1997 and 2006 PM2.5 standards for states in the eastern United States. The proposed rule would both identify the emissions from states in the eastern U.S. that significantly contribute to nonattainment and interfere with maintenance of the NAAQS in downwind states, and prohibit such emissions. States are obligated to submit SIPs to EPA addressing the provisions of section 110(a)(2), including the transport provisions of section 110(a)(2)(D)(i)(I), within 3 years of the promulgation of a new or revised NAAQS. For the 1997 NAAQS, these SIPs were due in 2000. On April 25, 2005 (effective May 25, 2005) EPA issued findings that states had failed to submit SIPs to satisfy the requirements of section 110(a)(2)(D)(i) of the Act under the 199 7 ozone and PM2.5 standards. 70 FR 21147, April 25, 2005. These findings started a 2
- year clock for the promulgation of a FIP by EPA unless, prior to that time, each state makes a submission to meet the requirements of 110(a)(2)(D)(i) and EPA approves the submission. This 2
- year period expired in May 2007. Because the Court found CAIR76

inadequate to satisfy the requirements of 110(a)(2)(D)(i)(I), neither EPA’s FIP implementing the requirements of CAIR nor any
s tates SIPs that relied on CAIR to satisfy th e requirements of this section, are adequate to meet the requirements of section 110(a)(2)(D)(i)(I). EPA’s obligation to issue a FIP has therefore not yet been met. The requirements of the FIPs proposed in this rule are designed to address this obligatio n. Revisions to the 1997 PM2.5 standards were signed by the Administrator on September 21, 2006, and published in the Federal Register on October 17, 2006. 71 FR 61144 . The revisions were effective December 18, 2006. EPA interprets the 3 year deadline for submission of 110(a)(2) SIPs to be 3 years from the date of signature. Accordingly, for the 2006 revisions to the PM2.5 NAAQS, the SIPs under 110(a)(2) were due on September 21, 2009. On [ADD CITE TO FINDINGS NOTICE] 2010, EPA issued a notice making findings that states had not submitted SIPs under the 2006 PM2.5 NAAQS by the September 2009 deadline. These findings started a 2
- year clock for the promulgation of a FIP by EPA unless, prior to that time, each state makes a submission to meet the requirements of 110(a)(2)(D)(i)(I) and EPA approves the submission. This 2
- year period will expire on [ add date 2 years from notice of findings] . This proposal is designed to provide FIPs for the 2006 standards to ensure that the 110(a)(2)(D)(i)(I) obligation i s fully satisfied as it77

relates to those standards. EPA also notes that under FIPs, reduction requirements are immediately effective and thus FIPs provide for the most expeditious means to implement emissions reduction requirements . c. Address T ransport Requirements w ith Respect to the 1997 O zone S tandards This proposed rule, in concert with other actions, largely eliminates upwind state emissions that contribute significantly to nonattainment in, or interfere with maintenance by , any other state with res pect to the 1997 8
- hour ozone NAAQS . EPA will issue a subsequent proposal for the 1997 8
- hour ozone NAAQS to address fully the requirements of CAA Section 110(a)(2)(D)(i)(I). EPA’s goal is to fully address transport requirements for the 1997 ozone standa rds as soon as possible. d. Provide for a Smooth T ransition f rom E xisting P rograms In addressing the Court remand in a way that satisfies the CAA transport requirements, EPA is also mindful of the need to ensure a smooth transition from the existing requ irements. Substantial improvements in air quality have resulted from those requirements with associated health benefits. It is important not to lose those benefits as the new requirements move forward. It is also important to move quickly with those por tions of the new requirements that provide the greatest benefits. 2. Key Guiding P rinciples78

a. Appropriately I dentify Necessary Upwind Reductions Emissions from upwind states can, alone or in combination with local emissions, result in air quality levels that exceed the NAAQS and jeopardize the health of residents in downwind communities. Each upwind state is required by the “good neighbor provision” to eliminate its individual significant contribution to downwind state nonattainment and to eliminate emi ssions that interfere with downwind states’ maintenance of the air quality standards. The Act does not require upwind states to eliminate all emissions that affect downwind air quality or shift responsibility for attaining the NAAQS to the upwind states. Instead, the “good neighbor provision” requires each upwind state to, within 3 years of promulgation or revision of a NAAQS, submit a SIP to prohibit those emissions that significantly contribute to nonattainment or interfere with maintenance downwind. T he prohibition on these emissions is intended to assist downwind states as they design strategies for ensuring that the NAAQS are attained and maintained. In practice, it is very complex for individual states to address the transport requirements. Gener ally for transport of ozone, and for transport of sulfate and nitrate fine particles, each downwind area is affected by emissions from multiple upwind states. In addition, in many cases states are simultaneously both upwind and downwind of one another. Further, only79

emissions that will significantly contribute to nonattainment or interfere with maintenance in another state are prohibited. Thus, an upwind state’s obligations are affected by the air quality downwind. Downwind air quality, in turn, is affe cted by both local emissions and the cumulative impact of emissions from all of the contributing upwind states. The problem of interstate transport is thus extremely complex and any remedy must acknowledge the inherent complexity of the problem. It is appropriate for EPA in developing such a remedy to be mindful of the interaction between upwind emissions controls and local emissions controls. The EPA continues to conclude , as it did in developing the CAIR, that it would be difficult if not impossibl e for many nonattainment areas to reach attainment through local measures alone, and EPA finds no information developed subsequent to development of CAIR to alter this conclusion. At the time of the proposed CAIR rule, EPA conducted a local measures analy sis represent ing an ambitious set of measures and emissions reductions that may in fact be difficult to achieve in practice. (Ref: Section IX of Technical Support Document for the Interstate Air Quality Rule Air Quality Modeling Analyses, January 2004). This analysis was intended to provide illustrative examples of the nature of location measures and possible reductions. This analysis was not intended to80

precisely identify local emissions control measures that may be available in a particular area. The EPA continues to believe that a strategy based on adopting cost effective controls on transported pollutants as a first step will produce a more reasonable, equitable, and optimal strategy than one beginning with local controls. The local measures analys es we conducted were not, however, intended to develop a specific or “optimal” regional and local attainment strategy for any given area. Rather, the analysis was intended to evaluate whether, in light of available local measures, it is likely to be neces sary to reduce significant regional transport from upwind states. EPA continue s to believe that the two local measures analyses that were conducted for the CAIR strongly support the need for regional reductions of SO 2 and NOX . In conclusion, EPA believes that the proposed rule represents the best approach for identifying upwind state emissions that significantly contribute to nonattainment in, or interfere with maintenance by, downwind states. b. Ensuring That Pollution Controls Operate The proposed Transport Rule would , by 2012 , cap emissions of SO 2 and NOX on a state -by
- state basis and guarantee that existing and planned pollution controls operate. EPA is convinced that the considerable benefits to air quality and public health that have been achieved must be ensured going81

forward. Keeping emissions of SO 2 and NO x from increasing by 2012 in 27 states and DC assures that recent gains are maintained and that states that significantly contribute to downwind PM2.5 nonattainment and maintenance areas do no t increase their contribution to those areas . Further, this proposal would maintain the ozone season emissions reductions achieved since 2005 in 2 6 s tates , ensuring that states that significantly contribute to downwind ozone nonattainment and maintenance areas do not increase their contribution to those
areas. Table s III.A- 2 and III.A
- 3 in section III.A, previously, show the projected EGU emissions for the 2012 phase of the Transport Rule . c. Provide Workable Approach for EPA and S tates Another important goal in developing the proposed requirements is to provide requirements that can, as a practical matter, be implemented by both EPA and state air quality agencies. Both EPA and state resources are limited and EPA recognizes the importance of developing re quirements that make efficient use of limited EPA and state resources. EPA also notes that the air quality improvements brought about by reducing transport can greatly assist states in the development of SIPs and attainment demonstrations. d. Ensure a Reliable P ower S upply EPA recognizes that requirements for EGUs must be mindful82

of the variability in the operation of the power grid, and that any requirements for broad reductions should be structured in a way that ensures a reliable power supply. e. Provide for Cost
- effectiveness EPA believes that is important to keep both cost
effectiveness and air quality objectives in mind in addressing the CAA transport requirements. f. Provide I ncentives and F lexibility to the Regulated C ommunity EPA seeks to provide approaches that provide regulated owners/operators of sources with the incentive to achieve all cost - effective reductions. EPA’s experience shows that providing this incentive, and the flexibility to seek alternatives to less cost
- effective controls, pr ovides for greater environmental protection at reduced cost. D. Why does this proposed rule focus on the eastern half of the United States? For this proposal, we identified a 37 state region for the technical analysis, including all states east of the Ro ckies, from the Dakotas through Texas eastward. Western states also need to address the requirements of section 110(a)(2)(D)(i)(I) of the CAA . However, the transport issues in the eastern United States are analytically distinct and this rule focuses only on that subset of the 110(a)(2)(D)(i)(I) issues. First, interstate transport of PM2.5 and ozone is a83

substantial and critical component for attaining the ozone and PM2.5 NAAQS in the eastern United States. The significant reductions in ambient air pollu tant concentrations since CAIR, due largely to the large reductions in transported emissions, only serves to reinforce this point. Second, in developing the CAIR, EPA found that interstate transport (particularly for anthropogenic emissions) made much
sma ller contributions to exceedances of the 1997 PM2.5 standards in the western United States. At the time, the only exceedances of the 15 μg/m3 in those states were in parts of California, and in Lincoln County (Libby), Montana. The Montana location has subsequently come into attainment. Technical information developed for EPA’s recently completed nonattainment designations suggests that interstate emission transport makes a relatively small contribution to exceedances in the western United States under the 2006 PM2.5 standards. For these designations, EPA identified several locations in the western U.S. with exceedances of the 24
- hour PM2. 5 standards. These locations were in California and other a few other western states: Alaska, Washington, Oregon, Utah, and Arizona. Technical support information describing the nature of the 24
- hour PM2.5 problem at each of these locations is availab le at: http://www.epa.gov/pmdesignations/2006standards/tech.htm . A review of this information suggests to EPA that the Western84

nonattainment problems are relatively local in nature with limited interstate transport. EPA requests comment on this assessment. E. Anticipated Rules Affecting Power Sector On January 12, 2010, the EPA Administrator outlined seven priorities for the Agency. One of them is to improve air quality. In her de scription of this priority she said, “EPA will develop a comprehensive strategy for a cleaner and more efficient power sector, with strong but achievable reduction goals for SO 2 , NOX , mercury and other air toxics.” In furtherance of this priority goal, an d to respond to statutory and judicial mandates, EPA is undertaking a series of regulatory actions over the course of the next 2 years that will affect the power sector in particular. The rules under the CAA will substantially reduce the emissions of SO 2 , NOX , mercury , and other air toxics . To the extent that the Agency has the legal authority to do so while fulfilling its obligations under the Act and other relevant statues, the Agency will also coordinate these utility
- related air pollution rules with upcoming regulations for the power sector from EPA’s Office of Water (OW) and its Office of Resource Conservation and Recovery (ORCR). EPA expects that this comprehensive set of requirements will yield substantial health and environmental benefits for the public, benefits that85

can be achieved while maintaining a reliable and affordable supply of electric power across the economy. In developing and promulgating these rules, the Agency will be providing the power industry with a much clearer picture of what EPA will require of it in the next decade. In addition to promulgating the rules themselves, the Agency will engage with other federal, state and local authorities as well as with stakeholders and the public at large with the goal of fostering investment s in compliance that represent the most efficient and forward
- looking expenditure of investor, shareholder and public funds, resulting, in turn, in the creation of a clean, efficient , and completely modern power sector. The major CAA rule s that will drive these compliance investments are : 1) this t ransport rule ; 2) potential future rules that may be needed to address transport under future revised ozone or fine particle health standards; 3) the CAA Section 112(d) standards; 4) revisions to the NSPS for co al and oil
- fired electric utility steam generating units ; and 5) best available retrofit technology (BART) requirements and other requirements that address visibility and regional haze . Within the planning and investment horizon for compliance with these rules, the EPA very likely will be compelled to respond a pending petition to set standards for the emissions of greenhouse gases from steam electric generating units under the86

New Source Performance Standard program. Furthermore, as set forth in the rece ntly promulgated reinterpretation of the Johnson Memo, beginning in 2011 new and modified sources of GHG emissions, including EGUs, will be subject to permits under the Prevention of Significant Deterioration program requiring them to adopt BACT for their GHG. F inally , EPA will also pursue with other federal agencies, states and other groups energy efficiency improvements in the use of electricity throughout the economy that will contribute to additional environmental and public health improvements that the Agency wants to provide while lowering the costs of realizing those improvements. A brief explanation of these major CAA rulemakings and activities is included later . Transport Rule . This proposed transport rule includes emissions reductions requireme nts for EGUs to address interstate transport under the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS, and the 2006 PM2.5 NAAQ S . Rules to Address Transport under Revised Air Quality Health Standards. EPA is currently reviewing both the ozone and fine particle NAAQS. If revised NAAQS are promulgated, they may result in additional requirements to reduce utility emissions to address transport. The ozone standard review will be completed by August 31, 2010, and the fine particle review by July 2011.87

State impleme ntation plan deadlines and attainment deadlines will flow from those dates. Section 112(d) Standards for Utility Units . In 2008, the D.C. Circuit Court vacated the CAMR and the 112(n) Revision Rule, which removed coal
- and oil
- fired electric utility ste am generating units from the section 112(c) list of sources subject to regulation . EPA is in the early stages of developing regulations under section 112 of the CAA that will require existing and new coal
- and oil
- fired utility units to meet emission s limits for mercury and other HAP emitted from these
sources. As required by section 112, EPA will issue a set of emission standards. In part, the section 112(d) rule will require that a ll existing major sources achieve the emission limits for HAPs which wil l be at least as stringent as the average emissions reduction currently achieved by the best performing 12 percent of these units. Additionally, any new major source will be required to meet emission limits that are at least as stringent as what is curren tly achieved by the best
performing single source . Currently , the Agency is seeking data
on five categories of HAP emissions: (1) acid gases (e.g., hydrochloric acid , hydrogen fluoride , and hydrogen cyanide ); (2) mercury; (3) Non
- Hg metals (e.g., lead, ca dmium, selenium, and arsenic ); (4) dioxins/fur ans; and, (5) other organic hazardous air pollutants. EPA expects to receive the requested data,88

including stack testing results, by September 2010. EPA has agreed to sign the proposed rule by March 16, 2011, and sign the final rule no later than November 16, 2011. EPA may provide existing sources up to 3 years to comply with section 112(d) standards, and the CAA authorizes the permit authority to grant a 1 year extension of the compliance date on a case
-by
- c ase basis if such extension is necessary for the installation of controls. The CAA requires new sources to comply on the
e ffective date of the final rule or at startup, whichever is later. If EPA were to provide 3 years for compliance with the section 11 2(d) standards, compliance would generally be required by early 2015. In developing these rules, EPA will endeavor to proceed in a way that provides all stakeholders and other federal, state and local decision
-makers with ongoing, up
- to - date information
about the full suite of environmental responsibilities that the power sector must undertake. This, in turn, will enable power companies and others whose policies and decisions affect their investment choice to adopt compliance strategies that take full advantage of co
- control opportunities and efficiencies and other approaches to maximizing the cost
- effectiveness and leveraging benefits of their investments. New Source Performance Standards . NSPS are administered under section 111 of the CAA. The standar ds for new, modified,89

and reconstructed steam EGUs are contained in 40 CFR Part 60 subpart Da , which was last amended in 2006. The current structure of subpart Da sets output
-based (i.e., lbs of emission/MWh) emission limits for NOX and SO 2 and optional
o utput -based standards for particulate matter. EPA is currently
re - evaluating the specific emission limits in Subpart Da to determine whether they reflect the degree of emission limitation achievable through the application of the best system of emission r eduction, which the Administrator determines has been adequately demonstrated . The current NSPS covers any new, reconstructed, or modified unit. Regional Haze/BART . States are required to develop SIPs that address regional haze in scenic areas such as n ational parks and wilderness areas. EPA regulations for regional haze appear in Chapter 40 of the CFR in sections 51.308 and 51.309. One of the requirements of the regional haze SIPs is to provide for BART for large industrial sources including EGUs. Th e BART provisions affect EGUs put into operation between 1962 and 1977. Energy Efficiency . Policies that will promote efficient use of electric power can be an integral, highly cost
- effective component of power companies’ compliance strategies. Redu cing demand for electricity can in itself achieve large emissions reductions and public health benefits, while enhancing the reliability of the grid. It can also lower the cost of90

emissions reductions for consumers of electricity and for the power industr y, as investments are avoided in unnecessary infrastructure. EPA does not have sole responsibility for the development of energy policy to promote efficiency. To facilitate this component of the power sector’s compliance strategy, EPA intends to engage with other federal, state, and local agencies whose policies and actions can make it easier for power companies to adopt, or benefit from, energy efficiency investments in their compliance strategies. EPA will continue to use its authorities to advance en ergy efficiency by providing incentives for energy efficiency in our regulatory programs (e.g. , output -based standards) and through our successful existing voluntary programs such as ENERGY STAR. The Department of Energy (DOE) also has considerable resour ces to encourage efficient use of electricity. Additional resources have been made available under the American Recovery and Reinvestment Act to both DOE and EPA to promote energy efficiency. State governments, both in their environmental programs and th rough their public service commissions which regulate electric utility rates can promote energy efficiency. Many state governments have been leaders in promoting efficient use of electricity through such mechanisms as energy efficiency standards and deman d response, and EPA and DOE are assisting state governments in this effort. Local91

governments as well, through building codes, zoning, and other actions, can and do promote end
- use energy efficiency. The Federal Energy Regulatory Commission (FERC) regula tes wholesale electricity markets and sets mandatory reliability standards to assure a safe reliable power system. In carrying out this mission FERC recognizes that energy efficiency is a resource, to be considered along with other energy resources in rel iability and economic planning. All of these entities will need to work in concert to achieve a truly efficient, reliable, cost effective electric power system. The Administration is committed to meeting this challenge. Non -Air Office Regulations . EPA is also working on three additional rules that will have potential impacts on the power sector. ORCR is issuing revised regulations dealing with coal combustion residues in early Spring 2010, which are the combustion byproducts associated with the use of coal as a fuel. OW is issuing two rules over the next several years. One will regulate cooling water intake structures. The other will revise the effluent guidelines for wastewater discharges from power plants. Each of these rules has cost implicat ions to the power sector, and the Agency intends to coordinate these regulations with the upcoming air regulations. We intend to maximize92

reductions in pollution while maintaining cost
- effective solutions. As a first step to carrying out its commitment to promote and facilitate the most cost
- effective and forward
- looking compliance investments and strategies on the part of the power sector, EPA will conduct extensive outreach concerning the full range of the upcoming environmental responsibilities of the
s ector as it proposes the Transport Rule . Upon this proposal, the Agency will begin an outreach effort with the public, the regulated community, state air regulators, and others to (1) describe the Transport Rule proposal, and (2) provide information on the 2011 section 112 standards for utility units and other upcoming EPA rulemakings affecting the power sector. The intent will be to inform all stakeholders of the industry’s obligations and opportunities for the industry to use investments in SO 2 and NOX reductions to help smooth transition to compliance with the Section 112(d) standards applicable to utility units. At the same time EPA also intends to expand its outreach to others

– - including Public Utility Commissions ( PUCs ) and State Energy Offices, FERC , and Department of Energy (DOE )
- – who can play a significant role in promoting or requiring investment in energy efficiency. EPA intends to continue these efforts over93

time as more information becomes available in the development of the various rulemakings under development for the power sector. IV. Defining “ S ignificant Contribution” and “ Interference With Maintenance ” This section describes EPA’s proposed approach to define emissions that significantly contribute to nonattainment or interfere with maintenance of the PM2.5 and ozone NAAQS downwind. The section begins by providing background on how “significant contribution” and “interference with maintenance” were defined in the past by EPA for the NO X SIP Call and the CAIR, describing past Court opinions on EPA’s approach, and presenting an overview of EPA’s proposed Transport Rule approach (section IV.A.). Next , section IV.B describes the proposed approach to identify upwind contributing states. Section IV.C details the air quality modeling appr oach and results used for this proposed rule. Section IV.D provides a detailed description of EPA’s proposed approach to quantify emissions that significantly contribute and interfere with maintenance. Section IV.E includes proposed state emissions budge ts before accounting for the inherent variability in power system operations . Section IV. F discusses the inherent variability in power system operations , proposes variability limits on the state budgets, and presents projected emission s reduction results. Section IV. G describes how the proposed approach is consistent with94

judicial opinions. Finally, section IV. H lists alternative approaches to defining significant contribution and interference with maintenance that EPA evaluated but is not proposing. A. Background 1. Approach U sed in NO X SIP Call and the CAIR a. Significant C ontribution Two rules EPA promulgated that address interstate transport of pollutants are the NO X SIP Call (63 FR 57356; October 27, 1998) and the CAIR (70 FR 25162; May 12, 2005), which are described in section III.B. In both of these rules, EPA used a 2
- step approach to quantify significant contribution. The approaches used in both rules were similar. In the first step, EPA applied an air quality threshold to determine a set of upwind states whose potential for significant contribution should be evaluated further. That is, EPA compared the contributions that individual upwind states make to downwind receptors and identified states whose contributions were greater than the specif ied threshold amount. EPA referred to these states as significant contributors but did not rely on this first step to quantify or measure the states’ significant contribution. In the second step, EPA determined the quantity of emissions that the states co llectively could remove using highly cost - effective controls. EPA defined this quantity of emissions95

as the “significant contribution.” The approach used in each rule is described in more detail, later . NOX SIP Call . EPA addressed the section 110(a)(2)( D)(i)(I) requirement to prohibit emissions that significantly contribute to downwind nonattainment in the NO X SIP Call. To do so, EPA developed a methodology for identifying emissions that constitute upwind states’ “significant contribution.” EPA determi ned that emissions “contribute” to nonattainment downwind if they have an impact on nonattainment downwind (62 FR 60325). EPA established several criteria or factors for the “significant contribution” test (and further indicated that the same criteria sho uld apply to the “interfere with maintenance” provision): 14 EPA determined the amount of emissions that significantly contribute to downwind nonattainment from sources in a particular upwind state by: (i) evaluating, with respect to each upwind state, several air quality related factors, including determining that all emissions from the state have a sufficiently great impact downwind (in the context of the collective contribution nature of the ozone problem); and (ii)

14 In the NO X SIP Call, because the same criteria applied, the discuss ion of the “contribute significantly to nonattainment” test generally also applied to the “interfere with maintenance” test. However, in the NO X SIP Call, EPA stated that the “interfere with maintenance” test applied with respect to only the 8
- hour ozone NAAQS (63 FR 57379
- 80).96

determining the amount of that state’s emissions that can be eliminated through the application of cost
- effective controls (63 FR 57403). Air Quality Factor . The first factor that EPA used to determine the amount of emissions that significantly contribute to downwind nonattainment was the air quality factor, consisting of an evaluation of the impact on downwind air quality of the upwind state’s emissions.

EPA specifically considered three air quality factors with respect to each upwind state:

 The overall nature of the ozone problem ( i.e. , “co llective contribution”);  The extent of the downwind nonattainment problems to which the upwind state’s emissions are linked, including the ambient impact of controls required under the CAA or otherwise implemented in the downwind areas; and  The ambient imp act of the emissions from the upwind state’s sources on the downwind nonattainment problems (63 FR 57376). EPA explained the first factor, collective contribution, by noting, [V]irtually every nonattainment problem is caused by numerous sources over a wide geographic area...[. This] factor suggest[s] that the solution to the problem is the implementation over a wide area of controls on many sources, each of which may have a small or immeasurable ambient impact by itself (63 FR 57377). The second air qual ity factor is the extent of downwind nonattainment problems. EPA considered the then
- current air quality of the area, the predicted future air quality (assuming97

implementation of required controls but not the transport requirements that were the subject o f the NO X SIP Call), and, when air quality designations had already been made, the boundaries of the area in light of designation status (63 FR 57377). 15 EPA applied the third air quality factor by projecting the amount of the upwind state’s entire invento ry of anthropogenic emissions to the year 2007, and then quantifying the impact of those emissions on downwind nonattainment through the appropriate air quality modeling techniques. 16 Specifically, (i) EPA determined the minimum threshold impact that the upwind state’s emissions must have on a downwind nonattainment area to be considered potentially to contribute significantly to nonattainment; and then (ii) for states with impacts above that threshold, EPA developed a set of metrics for further evaluating the contribution of the upwind state’s emissions on a downwind
15 EPA explained in the NO X SIP Call, “ It should be reiterated that EPA relied on the designated area solely as a proxy to determine which areas have air quality in nonattainment. This proxy is readily available under the 1
- hour NAAQS because areas have long been designated nonattainment. The EPA’s reliance on designated nonattainment areas for purposes of the 1
- hour NAAQS does not indicate that the reference in section 110(a)(2)(D)(i)(I) to “nonattainment” should be interpret ed to refer to areas designated nonattainment. ” (63 FR 57375 , footnote 25) 16 Although EPA’s air quality modeling techniques examined all of the upwind s tate’s emissions of ozone precursors (including VOC and NO X ), only the NO X emissions had meaningful int erstate impacts.98

nonattainment area (63 FR 57378). EPA referred to states with emissions that had a sufficiently great impact as significant contributors; however, the precise amount of their significant contr ibution was not calculated until the next step. B ecause the ozone problem is caused by many relatively small contributions even relatively small contributors must participate in the solution. For this reason, EPA determined that even a relatively small c ontribution can be significant contribution given the nature of the problem , and established relatively low thresholds . Cost Factor . The cost factor is the second major factor that EPA applied to determine the significant contribution to nonattainment: “EPA...determined whether any amounts of the NO X emissions may be eliminated through controls that, on a cost
per - ton basis, may be considered to be highly cost effective” (63 FR 57377) . Applying this cost factor on top of the air quality factor, EPA dete rmined that emissions that were both: (a) from states that exceeded the air quality thresholds and (b) could be eliminated through the application of highly cost
effective controls constituted a given state’s significant contribution. Choice of Highly Cos t - effective Standard . EPA chose the standard of “highly cost
- effective” in order to assure state flexibility in selecting control strategies to meet the99

emissions reduction requirements of the rulemaking. That is, the rulemaking required the states to achieve specified levels of emissions reductions

– the levels achievable if states implemented the control strategies that EPA identified as highly cost - effective

– but the rulemaking did not mandate those highly cost - effective control strategies, or any oth er control strategy. Indeed, in calculating the amount of the required emissions reductions by assuming the implementation of highly cost - effective control strategies, EPA assured that other control strategies

– ones that were cost effective, if not highl y cost effective
- remained available to the states. Determination of Highly Cost
- Effective Amount . EPA determined the dollar amount considered to be highly cost effective by reference to the cost
- effectiveness of recently promulgated or proposed NO X cont rols. EPA determined that the average cost effectiveness of controls ranged up to approximately $1,800 per ton of NO X removed (1990$) on an annual basis. The EPA considered the controls in the reference list to be cost
- effective. EPA established $2,000 per ton (1990$) in average cost
effectiveness for summer ozone season emissions reductions as, at least directionally, the highly cost
- effective amount. Identifying this amount on an ozone season basis was appropriate because the NO X SIP Call concerned t he ozone standard, for which100

emissions reductions during only the summer ozone season are necessary. In determining the highly cost
- effective amount, EPA analyzed costs on a regionwide basis, and assumed a cap and trade program for EGUs and large non
- EGU boilers and turbines. Source Categories . EPA then determined that the source categories for which highly cost
- effective controls were available included EGUs, large industrial boilers and turbines, and cement kilns. At the same time, EPA determined, for those source categories, the level of emissions reductions in each state that would result from the application of all controls that would be highly cost
- effective and that would be feasible. The EPA considered other source categories, but found that high ly cost
- effective controls were not available for various reasons, including the size of the sources, the relatively small amount of emissions from the sources, or the control costs. Other Factors . EPA also relied on several other, secondary consideratio ns to identify the required amount of emissions reductions. The first concerned the consistency of regional reductions with downwind attainment needs. The second general consideration was “the overall fairness of the control regimes” to which the downwin d and upwind areas were subject. The third general consideration was “general cost considerations.” The EPA noted that “in general, areas that currently have, or that in the past have had, nonattainment problems ... have already101

incurred ozone control co sts.” The next set of controls available to these nonattainment areas would be more expensive than the controls available to the upwind areas. The EPA found that this cost scenario further confirmed the reasonableness of the upwind control obligations (6 3 FR 57379). In the NO X SIP Call, EPA considered all of these factors together in determining the level of controls considered to be highly cost
- effective. Within the region, the nonattainment areas already had implemented required VOC and NO X controls th at covered much of their inventory. However, the upwind states in the region generally had not implemented such controls (except as needed to address their ozone nonattainment areas). In this context, EPA considered it reasonable to impose an additional control burden on the upwind states. Air quality modeling showed that residual nonattainment remained even with this additional level of upwind controls so that further reductions from downwind and/or upwind areas would be necessary. After ascertaining the controls that qualified as highly cost - effective, EPA developed a methodology for calculating the amount of NO X emissions that each state was required to reduce on grounds that those emissions contribute significantly to nonattainment downwind. The tota l amount of required NO X emissions reductions was the sum of the amounts that would be reduced by application of highly cost
- effective controls to each102

of the source categories for which EPA determined that such controls were available (63 FR 57378). Elect ric Generating Units. The largest of the source categories discussed previously was EGUs. EPA determined the amount of reductions associated with EGU controls by applying the control rate that EPA considered to reflect highly cost
- effective controls to ea ch state’s EGU heat input (adjusted for projected growth) (70 FR 25173.) In the NO X SIP Call, EPA evaluated the costs of control on a region
- wide basis. CAIR . In the CAIR, EPA again addressed the section 110(a)(2)(D)(i)(I) requirement to prohibit emissio ns that significantly contribute to downwind nonattainment (70 FR 25162). While the NO X SIP Call had addressed significant contribution with respect to the 1997 ozone NAAQS, the CAIR addressed significant contribution with respect to both the ozone and annual PM2.5 NAAQS promulgated in 1997 . In the CAIR, EPA used a methodology to identify states’ significant contribution based on and very similar to the methodology used in the NO X SIP Call. To quantify the amounts of emissions that contribute significan tly to nonattainment, EPA explained in the CAIR that the Agency primarily focused on the air quality factor reflecting the upwind state’s ambient impact on downwind103

nonattainment areas, and the cost factor of highly cost
effective controls. See 70 FR 2517 4. Air Quality Factor

– PM2.5 . EPA employed air quality modeling techniques to assess the impact of each upwind state’s entire inventory of anthropogenic SO 2 and NOX emissions on downwind nonattainment and maintenance for the annual PM2.5 NAAQS. 17 EPA det ermined that upwind NO X and SO 2 emissions contribute significantly to annual PM2.5 nonattainment as of the year 2010. As in the NO X SIP Call, EPA used a 2
- step approach to quantify significant contribution. In the CAIR, in the first step EPA adopted a thr eshold air quality impact of 0.2 μg/m3 for PM2.5 . An upwind state with contributions to downwind nonattainment below this level would not be subject to regulatory requirements, but a state with contributions at or higher than this level would be subject t o further evaluation (70 FR 25174
- 75). This level reflects the fact that PM2.5 nonattainment, like ozone, is caused by many sources in a broad region and therefore may be solved only by controlling sources throughout the region. As with the NO X SIP Call, the collective contribution condition

17 EPA did not address 24
- hour PM2.5 NAAQS in CAIR, only the annual PM2.5 NAAQS.104

of PM2.5 air quality is reflected in the relatively low threshold (70 FR 25175). Air Quality Factor

– 8
- Hour Ozone . EPA employed air quality modeling techniques to assess the impact of each upwind state’s inventory of NOX and VOC emissions on downwind nonattainment. The EPA determined that upwind NO X emissions contribute significantly to 8
- hour ozone nonattainment as of the year 2010. Therefore, EPA projected NO X emissions to the year 2010, assuming certain required controls (but not controls required under the CAIR), and then modeled the impact of those projected emissions on downwind 8
- hour ozone nonattainment in that year (70 FR 25175). EPA used the same threshold amounts and metrics for 8
- hour ozone that it used i n the NO X SIP Call. That is, emissions from an upwind state were found to contribute significantly to nonattainment if the maximum contribution was at least 2 parts per billion, the average contribution greater than one percent, and certain other numerica l criteria were met. EPA also evaluated frequency, magnitude, and relative amounts of contribution to determine which linkages were significant before costs were considered. Cost Factor. The second step in the 2
- step process is to apply the cost factor. As in the NO X SIP Call, EPA interpreted this factor as mandating emissions reductions in amounts that105

would result from application of highly cost
- effective controls. In the CAIR, EPA determined the level of costs that would be “highly cost
- effective” o n a regional basis by reference to the cost effectiveness of other recent controls. EPA concluded that EGUs were the only source category for which highly cost
effective SO 2 and NOX controls were available at the time. EPA determined as “highly cost
- effe ctive” the dollar amount of cost effectiveness that falls near the low end of a reference range of control costs. See 70 FR 25175. In the CAIR, as in the NO X SIP Call, EPA analyzed the costs of control on a regionwide basis. Other Factors . As with the NOX SIP Call, EPA considered other factors that influence the application of the air quality and cost factors, and that confirm the conclusions concerning the amounts of emissions that upwind states must eliminate as contributing significantly to downwind n onattainment. See 70 FR 25175 . b. Interference w ith Maintenance Section 110(a)(2)(D)(i)(I) requires that SIPs for national primary and secondary air quality standards contain adequate provisions prohibiting emissions in amounts that “interfere with maint enance by any other state” of any such standard. In the NO X SIP Call and in the CAIR, EPA gave the term “interfere with maintenance” a meaning much the same as the106

meaning given to the term “significant contribution.” That approach, which was found incons istent with the requirements of 110(a)(2)(D)(i)(I) are described later . EPA’s proposed new approach to interpreting “interfere with maintenance” is described in section IV.D, later . NOX SIP Call: In the NO X SIP call, EPA explained its approach as follows ( 63 FR 57379
- 80 ) : After an area has reached attainment of the 8
- hour NAAQS, that area is obligated to maintain that NAAQS. (See sections 110(a)(1) and 175A.) Emissions from sources in an upwind area may interfere with that maintenance. The EPA propos es to apply much the same approach in analyzing the first component of the “interfere
- with
-maintenance” issue, which is identifying the downwind areas whose maintenance of the NAAQS may suffer interference due to upwind emissions. The EPA has analyzed the "interfere
- with
maintenance" issue for the 8
- hour NAAQS by examining areas whose current air quality is monitored as attaining the 8
- hour NAAQS [or which have no current air quality monitoring], but for which air quality modeling shows nonattainment in the year 2007. This result is projected to occur, notwithstanding the imposition of certain controls required under the CAA, because of projected increases in emissions due to growth in emissions generating activity. Under these circumstances, emissions fr om upwind areas may interfere with the downwind area's ability to attain. Ascertaining the impact on the downwind area's air quality of the upwind area's emissions aids in determining whether the upwind emissions interfere with maintenance (62 FR 60326). In today’s action, EPA is taking the same positions with respect to the interfere
- with
-maintenance test as described in the notice of proposed rulemaking. In addition, the NO X SIP Call preamble stated: This [interfere
- with
-maintenance] requirement...doe s not, by its terms, incorporate the qualifier of "significantly." Even so, EPA believes that for present purposes, the term "interfere" should be interpreted much the same as the term107

"contribute significantly," that is, through the same weight
- of
- evidenc e approach. ... CAIR: In the CAIR, EPA also interpreted “interfere with maintenance” in a limited way. EPA only considered whether upwind state emissions eventually posed a maintenance problem for areas that EPA projected to be in nonattainment in 2010 (t he year that was the focus of the analysis of significant contribution to nonattainment). EPA did not examine whether areas in attainment in 2010 might face a maintenance problem either in 2010 or thereafter, so no upwind state controls were considered to assist such areas with maintaining clean air. The CAIR preamble stated ( 70 FR 25193, footnote 45 ) , “we believe the “interfere with maintenance” prong may come into play only in circumstances where EPA or the state can reasonably determine or project, bas ed on available data, that an [nonattainment] area in a downwind state will achieve attainment, but due to emissions growth or other relevant factors is likely to fall back into nonattainment.” 18

18 The CAIR final preamble stated: “EPA has evaluated the attainment status of the downwind receptors in 2010 and 2015, and has determined that each upwind s t ate’s 2010 and 2015 emissions reductions are necessary to the extent required by the rule because a downwind receptor linked to that upwind s tate will either (i) remain in nonattainment and continue to experience significant contribution to nonattainment f rom the upwind s tate’s emissions; or (ii) attain the relevant NAAQS but later revert to nonattainment due, for example, to continued growth of the emissions inventory.”108

In responding to comments on the CAIR proposal, we also used this interpretation of the maintenance provision to help support the need for Phase II CAIR reductions. For ozone, we conducted an analysis that looked at (1) the amount by which receptor locations were projected to attain in 2015 and (2) the year - to - year variability in ozone levels due to weather and other factors based on a review of historical monitoring data. This analysis concluded that areas within 3
- 5 ppb of the standard, and sometimes greater (e.g., Fulton County , Atlanta) had historic variability as great as 8 ppb, and that this variability suggests strongly that upwind states could be interfering with maintenance even if modeling shows attainment by up to these amounts. For PM2.5 , while we lacked historical data to support the same variability analysis, we characterized attaining the annual standard by 0.5 ug/m3 as “attaining by a narrow margin” thus giving rise to maintenance concerns, and noted that in past (mobile source) rules we had indicated that attainment by a margin of 10 percent or les s could be considered to raise maintenance concerns. 2. Judicial Opinions a. Significant C ontribution In North Carolina v. EPA , 531 F.3d. 896 (D.C. Cir. 2008), the Court held that the approach EPA used in CAIR to measur e each state’s significant contributi on was insufficient. EPA,109

the Court concluded, had failed to “measure[] the significant contribution from sources within an individual state to downwind nonattainment areas.” Id . at 907. The Court further reasoned that the lack of a state
- specific signi ficant contribution analysis made it impossible for EPA to show that the trading programs and state budgets established to implement the trading programs, effectuated the section 110(a)(2)(D)(i)(I) statutory mandate to eliminate emissions within the state that significantly contribute to nonattainment or interfere with maintenance in other states . Specifically, the court rejected the regional scope of EPA’s analysis. It reasoned that “because EPA evaluated whether its proposed emissions were ‘highly cost e ffective’ at the regionwide level assuming a trading program, it never measured the ‘significant contribution’ from sources within an individual state to downwind nonattainment areas.” Id . at 907. In reaching this conclusion, however, the Court also reco gnized that aspects of EPA’s methodology for analyzing significant contribution had been upheld in Michigan v. EPA , 213 F.3d 663 (D.C. Cir. 2000), and it left those holdings undisturbed. Specifica lly, the Court acknowledged its prior conclusion that “sign ificance may include cost” North Carolina , 531 F.3 d at 919 (citing Michigan 213 F.3d 677
- 79), and thus it is acceptable for EPA to use cost to “ draw the ‘significant contribution’ line ”.110

Id. The Court also recognized that Michigan approved EPA’s decision to apply a uniform emissions control requirement to all upwind states despite different levels of contribution. See North Carolina , 531 F.3d at 908. The Court thus concluded that while EPA must “measure each state’s ‘significant contribution’ to downwin d nonattainment” that measurement need not “directly correlate with each state’s individualized air quality impact on downwind nonattainment relative to other upwind states.” Id . at 908. In North Carolina , the Court also upheld several aspects of the air quality modeling EPA used in the significant contribution analysis. It upheld EPA’s use of whole state modeling, see id . at 923
- 26 , and deferred to EPA’s selection of the PM2.5 contribution threshold, see id . at 914
- 15. With regard to EPA’s application o f the methodology to individual states, the Court found that EPA had failed to respond to comments by Minnesota Power alleging errors in the application of this methodology to determine Minnesota’s contribution to downwind PM2.5 nonattainment area s . See i d . at 926
- 28. b. Interference With Maintenance In the CAIR case, t he Court also rejected EPA’s approach to the second prong of section 110(a)(2)(D)(i) (I) , holding that EPA’s failure to give independent meaning to the term “interfere with maintenance” was inconsistent with the statutory mandate.111

See North Carolina , 531 F.3d at 910. The Court rejected the approach used in CAIR reasoning that it “provide s no protection for downwind areas that, despite EPA’s predictions, still find themselves struggling to meet NAAQS due to upwind interference in 2010.” Id . at 910
- 11. 3. Overview of Proposed Approach In this section, EPA will explain how it proposes to identify which states are significantly contributing to downwind non
attainment and/or interfering with mai ntenance of the NAAQS at downwind sites and to quantify what that contribution is. In this action, EPA is proposing to use a two step approach to measuring each state’s significant contribution. The methodology used is based on the approach used in CAIR a nd the NOX SIP Call but modified to address the concerns raised by the Court. In the first step of this proposed approach, EPA uses air quality modeling to quantify individual states’ contributions to downwind nonattainment and maintenance sites in 2012. States whose contributions to any downwind sites are greater than 1 percent of the relevant NAAQS are considered “linked” to those sites for the purpose of the second step in the analysis. In the second step, EPA identifies the portion of each state’s co ntribution that constitutes its “significant contribution” and “interference with maintenance.” To do so, EPA uses maximum cost thresholds, informed by air quality112

considerations. Specifically, for each precursor pollutant(i.e. SO 2 and NOX for PM2.5 and NOX for ozone) emitted by the upwind states that EPA has identified as linked to NAAQS nonattainment and maintenance sites downwind, EPA identifies, through this process the reductions available in each individual upwind state at the appropriate maximum co st threshold. These emissions reductions are the amount of the upwind state’s significant contribution. The cost thresholds used in this portion of the analysis, in contrast to the thresholds used in CAIR and the NOX SIP Call, are informed by air quality considerations, in addition to a comparison of the cost of control in other regulatory contexts. Specific cost thresholds were developed for annual SO 2 , annual NOX , and ozone
- season NOX . Where appropriate, EPA developed higher and lower cost thresholds, based on the downwind air quality impact of emissions from different groups of states. Although EPA in the past has applied a uniform remedy to all states found to have a significant contribution, in this proposal EPA divides, for individual pollutants, the significantly contributing states into two groups

– those whose significant contribution can be eliminated at a lower cost threshold, and those whose significant contribution is not eliminated (to the extent that is has been identified in today’s propo sal) until they reach the higher cost threshold. The lower cost threshold applies to a113

state, if the reduction in emissions at that threshold eliminates nonattainment and maintenance problems at all “linked” sites. EPA considers that the maintenance con cept has two components: year - to - year variability in emissions and air quality, and continued maintenance of the air quality standard over time. Both components of maintenance are addressed in this proposal. Step One: Air Quality Analysis In step one of this proposed approach, EPA analyzes emissions from 37 states to quantify the impact of those emissions on downwind nonattainment and maintenance sites in 2012 ( see section IV.C for a detailed discussion of air quality modeling). To begin this analysis, E PA first identifies all monitors projected to be in nonattainment or, based on historic variability in air quality, projected to have maintenance problems in 2012. This baseline analysis takes into account emission s reductions associated with the implemen tation of all federal rules promulgated by December 2008 and assumes that the CAIR is not in effect. This baseline presents a unique situation. EPA has been directed to replace the CAIR; yet the CAIR remains in place and has led to significant emissions reductions in many states.114

A key step in the process of developing a 110(a)(2)(D)(i)(I) rule involves analyzing existing (base case) emissions to determine which states significantly contribute to downwind nonattainment and maintenance areas. EPA cannot prejudge at this stage which states will be affected by the rule. For example, a state affected by CAIR may not be affected by the new rule and after the new rule goes into effect, the CAIR requirements will no longer apply. For a state covered by CAIR but not covered by the new rule, the CAIR requirements would not be replaced with new requirements, and therefore an increase in emissions relative to present levels could occur in that state. More fundamentally, the court has made clear that, due to lega l flaws, the CAIR rule cannot remain in place and must be replaced. If EPA’s base case analysis were to ignore this fact and assume that reductions from CAIR would continue indefinitely, areas that are in attainment solely due to controls required by CAIR would again face nonattainment problems because the existing protection from upwind pollution would not be replaced. For these reasons, EPA cannot assume in its base case analysis, that the reductions required by CAIR will continue to be achieved. Follow ing this logic, the 2012 base case shows emissions higher than current levels in some states. Because EPA has been directed to replace CAIR, EPA believes that for many states, the115

absence of the CAIR NO X program will lead to the status quo of the NOX Budget Program, which limits ozone
- season NO X emissions and ensures the operation of NO X controls in those states. Also , without the CAIR SO 2 program, emission requirements in many areas would revert to the comparatively less stringent requirements of the Tit le IV Acid Rain program. As a result, SO 2 emissions in many states would increase markedly in the 2012 base case relative to the present. Efforts to comply with ARP rules at the least
- cost would occur in many cases without the operation of existing scrubbers through use of readily available, inexpensive Title IV allowances. Notably, all known controls that are required under state laws, NSPS, consent decrees, and other enforceable binding commitments through 2014 are accounted for in the base case. It i s against this backdrop that the Transport Rule is analyzed and that significant contribution to nonattainment and interference with maintenance must be addressed. Step Two: Quantifying E ach S tate’s S ignificant C ontribution In step two, EPA identifies the portion of each state’s contributing emissions that constitute the emissions from that state that “significantly contribute to, or interfere with maintenance by” another state. To do so with respect to the 1997 ozone NAAQS, EPA analyzes the costs and ass ociated air quality impacts of reductions in ozone
- season NO X . To do so with116

respect to the 1997 and 2006 PM2.5 NAAQS, EPA analyzes the costs and associated air quality impacts of reductions in annual SO 2 and annual NO X . The analysis uses cost thresholds , informed by air quality considerations and applied on a state specific basis. EPA considered a number of factors, including air quality and cost factors because the circumstances that lead to nonattainment and maintenance problems at downwind sites are extremely complex. By using both cost and air quality factors, EPA’s analysis can address the different circumstances influencing the linkages between upwind and downwind states. As such, EPA believes it is appropriate to consider these factors in identi fying the emissions that must be prohibited. While we believe it is important to consider cost, we also recognize that we can’t “just pick a cost for the region and deem ‘significant’ any emissions that sources can eliminate more cheaply.” North Carolin a , 531 F.3d at 918. In contrast to the approach used in CAIR and the NO X SIP Call, the cost thresholds EPA uses in this proposed approach are informed by air quality considerations and applied on a state specific basis. EPA first develops state specific costs curves showing what level of emission reductions could be achieved at different cost levels in 2012 and 2014. EPA then uses a simplified air quality assessment tool to examine the impact of the reductions at specific cost levels, on downwind nonatta inment and maintenance117

sites. This approach allows EPA to identify specific cost breakpoints based on air quality considerations such as being a cost at which the air quality assessment analysis projects large numbers of downwind sites maintenance and non attainment problems would be resolved or cost criteria, such as being a cost where large emission reductions occur because a particular technology is widely implemented at that cost. EPA then evaluated the reasonableness of the cost breakpoints using a number of criteria to determine which of the breakpoints appropriately represented a cost threshold with which to define significant contribution. These thresholds are then applied on a state
- specific basis to quantify each individual state’s significant contribution. The remainder of this section provides further detail on the specific methodology developed by EPA and the application of this methodology to identify emissions that significantly contribute to or interfere with maintenance of the 1997 ozo ne NAAQS and the 1997 and 2006 PM2.5 NAAQS. B. Overview of Approach to I dentify C ontributing Upwind S tates This section describes EPA’s proposal to require reductions in upwind emissions of SO 2 and NOX to address PM2.5 transport and to require reductions in upwind emissions of NO X to address
ozone - related transport. In addition, this section provides an118

overview of EPA’s approach to identifying which states are subject to the proposed rule, and which states are not subject to the rule because their sourc es’ emissions were found to not significantly contribute to nonattainment of the PM2.5 or 8
- hour ozone standards or interfere with maintenance of those standards, in downwind states. The EPA assessed individual upwind states’ 2012 projected ambient impac ts on downwind nonattainment and maintenance receptors for a 37
- state region in the Eastern U.S., and established threshold values for PM2.5 and ozone to identify those states whose impact does not constitute a significant contribution to air quality viola tions in the downwind states. EPA used these same threshold values in considering the potential for upwind state emissions to interfere with maintenance of the PM2.5 and 8
- hour ozone NAAQS in downwind areas. The EPA used air quality modeling of emissions in each state to estimate the ambient impacts. The air quality modeling platform and approach to quantifying interstate contributions to PM2.5 and ozone are discussed in section IV.C. As noted previously , EPA considers that the maintenance concept has two components: year - to - year variability in emissions and air quality, and continued maintenance of the air quality standard over time. The way that EPA defined maintenance based on year
- to - year variability is discussed in119

section IV.C., and directly affec ts the proposed requirements of this rule. EPA also considered whether further reductions were necessary to ensure continued lack of interference with maintenance of the NAAQS over time. EPA concluded that in light of projected emission trends, and also considering the emissions reductions from this proposed rule, no further reductions are required solely for this purpose at PM and ozone receptors for which we are partially or fully determining significant contribution for the current NAAQS . ( See support ing information in docket.) 1. Background a. For the CAIR, how did EPA determine which pollutants were necessary to control to address interstate transport for PM2.5 ? Section II of the January 2004 CAIR proposal summarized key scientific and technical as pects of the occurrence, formation, and origins of PM2.5 , as well as findings and observations relevant to formulating control approaches for reducing the contribution of transport to fine particle problems (69 FR 4575
- 87). Key concepts and provisional co nclusions drawn from this discussion were summarized as follows in the preamble to the final CAIR: (1) Fine particles (measured as PM2.5 for the NAAQS) consist of a diverse mixture of substances that vary in size, chemical composition, and source. The PM2.5 includes both “primary”120

particles that are emitted directly to the atmosphere as particles, and “secondary” particles that form in the atmosphere through chemical reactions from gaseous precursors. The major components of fine particles in the Eastern U.S. can be grouped into five components: carbonaceous material (including both primary and secondary organic carbon and black carbon), sulfates, nitrates, ammonium, and crustal material, which includes suspended dust as well as some other directly emitte d materials. The major gaseous precursors of PM2.5 include SO 2 , NOX , NH 3 , and certain volatile organic compounds. (2) Examination of urban and rural monitors indicate that in the Eastern U.S., sulfates, carbonaceous material, nitrates, and ammonium asso ciated with sulfates and nitrates are typically the largest components of transported PM2.5 , while crustal material tends to be only a small fraction. (3) Atmospheric interactions among particulate ammonium sulfates and nitrates and gas phase nitric acid and ammonia vary with temperature, humidity, and location. Both ambient observations and modeling simulations suggest that regional SO 2 reductions are effective at reducing sulfate and associated ammonium, and, therefore, PM2.5 . Under certain conditions reductions in particulate ammonium sulfates can release ammonia as a gas, which then reacts with gaseous nitric acid to form nitrate particles, a phenomenon called “nitrate replacement.”121

In such conditions SO 2 reductions would be less effective in reducin g PM2.5 , unless accompanied by reductions in NO X emissions to address the potential increase in nitrates. (4) Reductions in ammonia can reduce the ammonium, but not the sulfate portion of sulfate particles. The relative efficacy of reducing nitrates throu gh NOX or ammonia control varies with atmospheric conditions; the highest particulate nitrate concentrations in the East tend to occur in cooler months and regions. At present, our knowledge about sources, emissions, control approaches, and costs is great er for NO X than for ammonia. Measures to reduce NO X from stationary and mobile sources have been implemented for more than 20 years. From a chemical perspective, as NO X reductions accumulate relative to ammonia, the atmospheric chemical system would move towards an equilibrium in which ammonium nitrate reductions become more responsive to further NO X reductions relative to ammonia reductions. (5) Much less is known about the sources of regional transport of carbonaceous material. Key uncertainties include how much of this material is due to biogenic as compared to anthropogenic sources, and how much is directly emitted as compared to formed in the atmosphere. Based on the understanding of current scientific and technical information, as well as EPA’s air quality modeling, as122

summarized in the CAIR proposal, EPA concluded that it was both appropriate and necessary to focus on control of SO 2 and NOX emissions as the most effective approach to reducing the contribution of interstate transport to PM2.5 . For the CAIR, the EPA did not include emissions controls that affect other components of PM2.5 , noting that “current information relating to sources and controls for other components identified in transported PM2.5 (carbonaceous particles, ammonium, and crusta l materials) does not, at this time, provide an adequate basis for regulating the regional transport of emissions responsible for these PM2.5 components.” (69 FR 4582). For all of these components, the lack of knowledge of and ability to quantify accurat ely the interstate transport of these components limited EPA’s ability to include these components in the CAIR. b. For the CAIR, h ow did EPA determine which p ollutants were
n ecessary to c ontrol to a ddress i nterstate t ransport for o zone? In the notice of proposed rulemaking for the CAIR, EPA provided the following characterization of the origin and distribution of 8
- hour ozone air quality problems: The ozone present at ground level as a principal component of photochemical smog is formed in sunlit conditio ns through atmospheric reactions of two main classes of precursor compound: VOCs and NO X (mainly NO and NO 2 ). The term “VOC” includes many123

classes of compounds that possess a wide range of chemical properties and atmospheric lifetimes, which helps determi ne their relative importance in forming ozone. Sources of VOCs include man
-made sources such as motor vehicles, chemical plants, refineries, and many consumer products, but also natural emissions from vegetation. Nitrogen oxides contributing to ozone formation are emitted by motor vehicles, power plants, and other combustion sources, with lesser amounts from natural processes including lightning and soils. Key aspects of current and projected inventories for NO X and VOC are summarized in section IV of the proposal notice and EPA websites (e.g., http://www.w.gov/ttn/chief . ) The relative importance of NO X and VOC in ozone formation and control varies with local
- and time
specific factors, including the relative amounts of VOC and NO X present. In rural are as with high concentrations of VOC from biogenic sources, ozone formation and control is governed by NO X . In some urban core situations, NO X concentrations can be high enough relative to VOC to suppress ozone formation locally, but still contribute to inc reased ozone downwind from the city. In such situations, VOC reductions are most effective at reducing ozone within the urban environment and immediately downwind. The formation of ozone increases with temperature and sunlight, which is one reason ozone levels are higher during the summer. Increased temperature also increases emissions of volatile man
-124

made and biogenic organics and can indirectly increase NO X as well (e.g., increased electricity generation for air conditioning). Summertime conditions al so bring increased episodes of large
- scale stagnation, which promote the build
- up of direct emissions and pollutants formed through atmospheric reactions over large regions. Authoritative assessments of ozone control approaches have concluded that, for re ducing regional scale ozone transport, a NO X control strategy would be most effective, whereas VOC reductions are most effective in more dense urbanized areas. Studies conducted in the 1970s established that ozone occurs on a regional scale (i.e. , 1000 s of kilometers) over much of the Eastern U.S., with elevated concentrations occurring in rural as well as metropolitan areas. While substantial progress has been made in reducing ozone in many urban areas, regional scale ozone transport is still an impor tant component of high ozone concentrations during the extended summer ozone season. A series of more recent progress reports discussing the effect of the NOX SIP Call reductions can be found on EPA’s website at: http://www.epa.gov/airmarkets/progress/pr ogress - reports.html . In the notice of proposed rulemaking for CAIR, EPA noted that we continue to rely on the assessment of ozone transport made in great depth by the OTAG in the mid
- 1990s. As indicated in the NO X SIP call proposal, the OTAG Regional and Urban Scale125

Modeling and Air Quality Analysis Work Groups concluded that regional NO X emissions reductions are effective in producing ozone benefits; the more NO X reduced, the greater the benefit. More recent assessments of ozone, for example those condu cted for the Regulatory Impact Analysis for the ozone standards in 2008, continue to show the importance of NO X transport. Information on these analyses can be found at EPA’s website at: http://www.epa.gov/ttn/ecas/regdata/RIAs/452_R_08_003.pdf . For addr essing interstate ozone transport in the CAIR, EPA addressed NO X emissions, but did not include requirements for VOCs. EPA believes that VOCs from some upwind states do indeed have an impact in some nearby downwind states, particularly over short transpor t distances. The EPA expects that states will need to examine the extent to which VOC emissions affect ozone pollution levels across state lines, and identify areas where multi
- state VOC strategies might assist in meeting the 8
- hour standard, in planning for attainment.
c . For the CAIR , which thresholds were used to identify states included under the rule? (1) Fine P articles In the CAIR, EPA used as the metric for identifying a state as significantly contributing (depending upon further consideration of costs) to downwind nonattainment, the predicted126

change, due to the upwind state’s NO X and SO 2 emissions, in annual 19 PM2.5 concentration in the downwind nonattainment area that receives the largest ambient impact. The EPA proposed this metric in the form of a range of alternatives for a “bright line,” that is, air quality impacts at or greater than the chosen threshold level indicated that the upwind state’s emissions do contribute significantly (depending on cost considerations), and that air quality impacts below the threshold indicate that the upwind state’s emissions do not contribute significantly to nonattainment. This metric addresses how much each state contributes to a downwind neighbor. EPA does not believe that a particular upwind state must contribute to multiple downwind receptors to be required to make emissions reductions under CAA section 110(a)(2)(D). Under this provision, an upwind state must include in the SIP adequate provisions that prohibit that state’s emissions that “contribute significantly to nonattainment in ... any other state....” (Emphasis added.) Our interpretation of this provision is that the emphasized terms make clear that the upwind state’s emissions must be controlled as long as they contribute significantly to a si ngle nonattainment area.
19 For the CAIR, 24
- hour PM2.5 was not at issue because there were little or no exceedan ces of the then
- existing 65 μg/m3 24
- hour standard127

As discussed in section II of the preamble to the final CAIR, EPA’s approach to evaluating a state’s impact on downwind nonattainment considered the entirety of the state’s SO 2 and NOX emissions, rather than treating them separatel y. We believed this approach was consistent with the chemical interactions in the atmosphere of SO 2 and NOX in forming PM2.5 . The contributions of SO 2 and NOX emissions are generally not additive, but rather are interrelated due to complex chemical react ions. In the CAIR proposal, EPA proposed to establish a state
level annual average PM2.5 contribution threshold from anthropogenic SO 2 and NOX emissions that was a small percentage of the annual air quality standard of 15.0 μg/m3. The EPA based this p roposal on the general concept that an upwind state’s contribution of a relatively low level of ambient impact should be regarded as significant (depending on the further assessment of the control costs). We based our reasoning on several factors. The EPA’s modeling indicates that at least some nonattainment areas will find it difficult to attain the standards without reductions in upwind emissions. In addition, our analysis of “base case” PM2.5 transport shows that, in general, PM2.5 nonattainment probl ems result from the combined impact of relatively small contributions from many upwind states, along with contributions from in
- state sources and, in some cases, substantially larger contributions from a subset of128

particular upwind states. In the NO X SIP Call rulemaking, we termed this pattern of contribution

– which is also present for ozone nonattainment

– “collective contribution.” In the case of PM2.5 , we have found collective contribution to be a pronounced feature of the PM2.5 transport problem, in p art because the annual nature of the PM2.5 NAAQS means that throughout the entire year and across a range of wind patterns

– rather than during just one season of the year or on only the few worst days during the year which may share a prevailing wind dire ction

– emissions from many upwind states affect the downwind nonattainment area. As a result, to address the transport affecting a given nonattainment or maintenance area, many upwind states must reduce their emissions, even though their individual contributions may be relatively small. As a result, for the CAIR EPA determined that a relatively low value for the PM2.5 transport contribution threshold was appropriate. For the final CAIR EPA decided to apply a threshold of 0.20 μg/m3 , such that any model r esult that is below this value (0.19 or less) indicates a lack of significant contribution, while values of 0.20 or higher exceeded the threshold. (2) Ozone For the CAIR ozone program, in assessing the contribution of upwind states to downwind 8
- hour ozon e nonattainment, EPA129

followed the approach used in the NO X SIP Call and employed the same contribution metrics, but with an updated model and updated inputs. The air quality modeling approach we proposed to quantify the impact of upwind emissions include d two different methodologies: zero
- out and source apportionment. EPA applied each methodology to estimate the impact of all of the upwind state’s anthropogenic NO X and VOC emissions on each downwind nonattainment areas. The EPA’s first step in evaluat ing the results of these methodologies was to remove from consideration those states whose upwind contributions were very low. Specifically, EPA considered an upwind state not to contribute significantly to a downwind nonattainment area if the state’s max imum contribution to the area was either (1) less than 2 ppb; or (2) less than one percent of total nonattainment in the downwind area; as indicated by either of the two modeling techniques. If the upwind state’s impact exceeded these thresholds, then EPA conducted a further evaluation to determine if the impact was high enough to meet the air quality portion of the “contribute significantly” standard. In doing so, EPA organized the outputs of the two modeling techniques into a set of “metrics.” The metr ics reflect three key contribution factors:130

• the magnitude of the contribution (actual amount of ozone contributed by emissions in the upwind state to nonattainment in the downwind area); • the frequency of the contribution (how often contributions above certain thresholds occur); and • the relative amount of the contribution ( the total ozone contributed by the upwind state compared to the total amount of nonattainment ozone in the downwind area). 2. Approach for Proposed Rule a. Which pollutants do we propose to control? For the proposed rule, EPA believes that the conclusions and findings in the final CAIR r egarding the nature of pollutant contributions are still appropriate. EPA proposes to continue to focus the PM2.5 transport requirements on S O 2 and NOX transport, and the ozone transport requirements on NO X . EPA recognizes that, in some circumstances, the state’s NO X contribution to PM2.5 in downwind states may be considerably smaller than the state’s SO 2 contribution to PM2.5 in downwind state s. In addition, for monitors in EPA’s speciation trends network that are located in southern states with warmer climates, the level of monitored nitrates can be very small. For these states, it is possible that annual NO X controls, within levels that cou ld realistically be achieved, would result in a very small change in ambient PM2.5 levels. EPA considered131

identifying states where this was the case. For a number of reasons, we propose not to take this course of action. First, these states can impact downwind states in cooler climates, and thus impact nitrate formation in those downwind states. For example, EPA modeling results show that Georgia’s emissions are linked to Ohio, Maryland, New Jersey and Pennsylvania where monitored nitrates are higher. Second, EPA is concerned with the possibility for the “nitrate replacement” effect described previously. That is, there is a possibility for increases in nitrate particles if SO 2 emissions decrease without accompanying decreases in NO X . Third, EPA believes that there would be important disbenefits to relaxing annual NO X requirements in those states. If for those states, EPA were to relax the annual NOX requirements currently required for their contribution to PM2.5 , annual NO X emissions would increase, w ith potentially harmful effects on visibility and nitrogen deposition. b. Thresholds For the proposed rule, as for CAIR, EPA uses air quality thresholds to identify states whose contributions do not warrant transport requirements. We propose air quality thresholds for annual PM2.5 , 24
- hour PM2.5 , and 8
- hour ozone. Each threshold is based on 1 percent of the NAAQS. As we found at the time of the CAIR, EPA’s analysis of “base case” PM2.5 transport shows that, in general, PM2.5132

nonattainment problems resul t from the combined impact of relatively small contributions from many upwind states, along with contributions from in
- state sources and, in some cases, substantially larger contributions from a subset of particular upwind states. For ozone, as we found i n the CAIR and the SIP call, we also found important contributions from multiple upwind states. In short, EPA continues to find an upwind “collective contribution” that is important to both PM2.5 and ozone. For annual PM2.5 for the final CAIR, as noted pr eviously , EPA decided to use a single
- digit value, 0 .2 μg/m3, rather than the two
- digit value in the proposed CAIR, 0.15 μg/m3. The rationale for the single digit value for the final rule was that a single digit is consistent with the EPA monitoring requirements in Part 50, Appendix N, section 4.3. The reporting requirements for annual PM2.5 require that: Annual PM2.5 standard design values shall be rounded to the nearest 0.1 μg/m3 (decimals 0.05 and greater are rounded up to the next 0.1, and any decimal lower than 0.05 is rounded down to the nearest 0.1 ). Because the design value is to be reported only to the nearest 0.1 μg/m3, EPA deemed it preferable for the final CAIR to select the threshold value at the nearest 0.1 ug/m3 as well, and hence one percent of the 15 μg/m3, rounded to the nearest 0.1 μg/m3 became 0.2 μg/m3.133

For the 24
- hour standard of 35 μg/m3, we attempted to apply the same rationale for determining a single
- digit air quality threshold. That is, we applied rounding conventions in Part 50, Appendix N to a value representing one percen t of the NAAQS. The rounding requirements for the 24
- hour standard are indicated in section 4.3 as follows: 24
- hour PM2.5 standard design values shall be rounded to the nearest 1 μg/m3 (decimals 0.5 and greater are rounded up to the nearest whole number, and any decimal lower than 0.5 is rounded down to the nearest whole number). One percent of the 24
- hour standard is 0.35 μg/m3 , and rounding to the nearest whole μg/m3 would yield an air quality threshold of zero. Thus applying the same rationale for the final CAIR, there would be no air quality threshold for 24
- hour PM2.5 , which EPA believes to be counterintuitive and unworkable as an approach for assessing interstate contributions. For the proposed rule, EPA proposes to decouple the precision of the ai r quality thresholds with the monitoring reporting requirements, and to use 2
- digit values representing one percent of the NAAQS, that is, 0.15 μg/m3 for the annual standard, and 0.35 μg/m3 for the 24

- hour standard. EPA believes there are a number of cons iderations favoring this approach. First, it provides for a consistent approach for the annual and 24
- hour standards. Second, the approach is readily applicable to any current and future NAAAQS. For example, if EPA were to134

retain the CAIR approach for t he annual standard, any future lowering of the PM2.5 NAAQS to below 15 μg/m3 would reduce the air quality threshold to 0.1 μg/m3 . This would occur because any value less than 0.15 μg/m3 (e.g., 0.14 μg/m3 ) would be rounded down to 0.1 μg/m3. EPA finds it within its discretion to adjust its approach to account for the additional considerations that were not in existence at the time of the final CAIR. For the proposal, EPA is proposing to take a more straightforward approach to air quality threshol ds for ozone than the multi
- factor approach we used for the NO X SIP call or for the CAIR. The proposed approach uses a single “bright line” threshold for ozone that is one percent of the 1997 8
- hour ozone standard of 0.08 ppm. As described later in s ecti on IV.C, the 1 percent threshold is averaged over multiple model days. EPA believes this to be a robust metric compared to previous metrics which might have relied on the maximum contribution on a single day. Under this approach, one percent of the NAAQS is a value of 0.8 ppb. State contributions of 0.8 ppb and higher are above the threshold; ozone contributions less than 0.8 ppb are below the threshold. EPA believes that this approach is preferable because it is a robust metric, it is consistent with t he approach for PM2.5 , and because it provides for a consistent approach that takes into account, and is applicable to, any future ozone standards below 0.08 ppm.135

EPA seeks comment on the pollutants and air quality thresholds used for identifying states to be included under the proposed rule. C. Air Quality Modeling Approach and Results 1. What a ir quality modeling p latform did EPA u se? a. Introduction In this section, we describe the air quality modeling performed to support the proposed rule. We used air quality modeling to (1) identify locations where we expect there to be nonattainment or maintenance problems for annual average PM2.5 , 24
- hour PM2.5 , and/or 8

- hour ozone for the analytic years chosen for this proposal, (2) quantify the impacts (i.e., air quality contributions) of SO 2 and NOX emissions from upwind states on downwind annual average and 24
- hour PM2.5 concentrations at monitoring sites projected to be nonattainment or have maintenance problems in 2012 for the 1997 annual and 2006 24
- hour PM2.5 NAAQS, respectively, (3) quantify the impacts of NO X emissions from upwind states on downwind 8
- hour ozone concentrations at monitoring sites projected to be nonattainment or have maintenance problems in 2012 for the 1997 ozone NAAQS, and (4)assess the he alth and welfare benefits of the emissions reductions expected to result from this proposal. This section includes information on the air quality model applied in support of the proposed rule, the meteorological and emissions inputs to136

these models, the evaluation of the air quality model compared to measured concentrations, and the procedures for projecting ozone and PM2.5 concentrations for future year scenarios. We also provide in this section the interstate contributions for annual average and 24
- hour PM2.5 , and 8
- hour ozone. The Air Quality Modeling Technical Support Document (AQMTSD) contains more detailed information on the air quality modeling aspects of this rule. To support the proposal, air quality modeling was performed for four emissions scen arios: a 2005 base year, a 2012 “no CAIR” base case, a 2014 “no CAIR” base case, and a 2014 control case that reflects the emissions reductions expected from the proposed FIP s . The remedy proposed for inclusion in the FIP s is described in section V.D. The modeling for 2005 was used as the base year for projecting air quality for each of the 3 future year scenarios. The 2012 base case modeling was used to identify future nonattainment and maintenance locations and to quantify the contributions of emission s in upwind states to annual average and 24
- hour PM2.5 and 8
- hour ozone. The 2014 base case and 2014 control case modeling were used to quantify the benefits of this proposal. For CAIR, EPA used two air quality models, the Comprehensive Air Quality Model with Extensions (CAMx), version 3.1 for modeling ozone and the Community Multiscale Air Quality137

Model (CMAQ) version 4.3 for modeling PM2.5 . Both CAMx and CMAQ are grid cell
-based, multi
-pollutant photochemical models that simulate the formation and fate of ozone and fine particles in the atmosphere. For the proposed rule EPA used CAMx version 5 20 to simulate ozone and PM2.5 concentrations for the 2005 base year and the 2012 and 2014 future year scenarios. The use of one model for both pollutants provides a more scientifically integrated “one atmosphere” approach versus using different models for ozone and PM2.5 . In addition, using a single model rather than two models is computationally more efficient. The CAMx model applications were designed to cover States in the Central and Eastern U.S. using a horizontal resolution of 12 x 12 km21 . The modeling region (i.e., modeling domain) extends from Texas northward to North Dakota and eastward to the East Coast and includes 37 states and the District of Columbi a. A map of the air quality modeling domain is provided in the AQMTSD. Both CAMx and CMAQ contain certain source apportionment tools that are designed to quantify the contribution of

20 Comprehensive Air Quality Model with Extensions Version 5 User’s Guide. Environ International Corporation. Novato, CA. March 2009. 21 The 12 km domain was nested within a coarse grid, 36 x 36 km modeling domain which covers the lower 48 states and adjacent portions of Canada and Mexico. Predictions from this Continental U.S. (CONUS) domain were used to provide initial and boundary concentrations for simulations in the 12 km domain.138

emissions from various sources and areas to ozone and PM2.5 component sp ecies in other downwind locations. The CAMx model was chosen for use in this rule because the source apportionment tools in this model have had extensive use and evaluation by states and industry. Also, the source apportionment tools in CAMx received favorable comments in a recent peer review 22
. The 2005
-based air quality modeling platform used for the proposal includes 2005 base year emissions and 2005 meteorology for modeling ozone and PM2.5 with CAMx. This platform provides an update to the now more hi storical data in the 2001
-based platform used for CAIR that included 2001 emissions, 2001 meteorology for modeling PM2.5 , and 1995 meteorology for modeling ozone. In the remainder of this section we provide an overview of (1) the emissions and meteorologi cal components of the 2005
- based platform , (2) the methods for projecting future nonattainment and maintenance along with a list of 2012 base case nonattainment and maintenance locations, (3) the approach to developing metrics to measure interstate contributions to annual and 24
- hour PM2.5 and ozone, and (4) the predicted interstate contributions to downwind nonattainment and maintenance. We also identify which predicted interstate

22 Arunachalam, S. Peer Review of Source Apportionment Tools in CAMx and CMAQ, EP
- D - 07
- 102. University of North Carolina, Institute for the Environment, August 2009.139

contributions are at or above the air quality impact thresholds described p reviously in section IV.B. b. Emissions Inventories Emissions estimates were made for a 2005 base year and for 2012 and 2014. All inventories include emissions from EGUs, nonEGU point sources, stationary nonpoint sources, onroad mobile sources, and nonroa d mobile sources. When emissions were only available at annual or monthly temporal resolutions, emissions modeling steps were applied to estimate hourly emissions. Point source emissions were assigned to modeling grid cells based on latitude and longitude in the inventory, and county total emissions were allocated to grid cells. Emissions of NO X , VOCs and PM2.5 were split into their components species using other data sources, to provide the modeling species needed by CAMx. Elevated point sources were i dentified for simulating releases of emissions from those sources in layers 2 and higher in CAMx. In addition to the anthropogenic emission sources described previously , hourly, gridded biogenic emissions were estimated for individual modeling days using the BEIS model version140

3.14 23 , 24
. The same biogenic emissions data were used in all scenarios modeled. (1) Development of 2005 Base Year Emissions Emissions inventory inputs representing the year 2005 were developed to provide a base year for forecasting future air quality, described in s ection IV.C.2. The 2005 National Emission Inventory (NEI), version 2 from October 6, 2008 , was the starting point for the U.S. inventories used for the 2005 air quality modeling. This inventory includes 2005
- specific dat a for point and mobile sources, while most nonpoint data were carried forward from version 3 of the 2002 NEI. In addition, a 2006 Canadian inventory and a 1999 Mexican inventory were used for the portions of Canada and Mexico within the modeling domains. Additional details on these inventories and the augmentation described here are available from the Emissions Inventory Technical Support Document (EITSD) for the Transport Rule.

23 Pouliot, G., Pierce., T. " A Tale of Two Models: A comparison of the Biogenic Emission Inventory System (BEIS) an d Model of Emissions of Gases and Aerosols from Nature (MEGAN) ", 7th Annual Community Multiscale Analysis System Conference, Chapel Hill, NC, October 6
- 8, 2008. 24 Donna Schwede, D., Pouliot, G., and Pierce, T. " Changes to the Biogenic Emissions Inventory S ystem Version 3 (BEIS3) ", 4th Annual Community Multiscale Analysis System Conference, Chapel Hill, NC, September 26
- 28, 2005.141

The onroad and nonroad emissions were primarily based on the National Mobile Inventory Model (NMIM) monthly, county, process level emissions from the 2005 NEI v2. The 2005 onroad mobile emissions were augmented for onroad gasoline emissions sources with emissions based on a draft version of the Motor Vehicle Emissions Simulator (MOVES) for carbon monoxide (CO), NOX , VOC, PM2.5 , and particulate matter less than ten microns (PM 10 ). While these data were preliminary, they more closely reflect the PM2.5 emissions from the final release of MOVES 2010. To account for the temperature dependence of PM2.5 , MOVES -based temperature adjustment factors were applied to gridded, hourly emissions using gridded, hourly meteorology. Additional information on this approach is available in the EITSD. The annual NO X and SO 2 emissions for EGUs in the 2005 NEI v2 are based primarily on data from EPA’s Clean Air Markets Division’s C ontinuous Emissions Monitoring (CEM) program, with other pollutants estimated using emission factors and the CEM annual heat input. For EGUs without CEMs, data were obtained from the states as included in the NEI. For modeling, the 2005 EGU emissions for SO 2 and NOX were augmented by using hourly CEM data to develop a temporal allocation approach of the 2005 NEI v2 emissions. The annual emissions themselves were unchanged,
and match closely with data from the CEM program except where states have provided data for partial CEM and non
- CEM units.142

The 2005 EGUs were identified as all units in 2005 that map to the units modeled by the version of the Integrated Planning Model ( IPM ) used for this proposal, and include records both with and without data submitted to the CEM program. Temporal profiles were used instead of the actual 2005 CEM data so that the temporal allocation approach could be consistent in the future year modeling . For the 2005 base year, the annual EGU NEI emissions were allocated to hourly emissions values needed for modeling based on the 2004, 2005, and 2006 CEM data. The NO X CEM data were used to create NO X - specific profiles, the SO 2 data were used to create SO 2 - specific profiles, and the heat input data were used to allocate all other pollutants. The 3 years of data were used for monthly and hourly profiles by state, while the 2005 data were used for the daily allocation from month, to preserve an appropriat e level of temporal variability. Other significant augmentations were also made to the 2005 NEI and include the following. The nonpoint inventory was augmented with oil and gas exploration inventory 25 which includes emissions in several states within the E astern U.S. 12 km modeling domain and additional states within the national 36 km modeling domain. The commercial marine category 3 (C3) vessel

25 The oil and gas exploration inventory was provided by the Western Regional Air Partnership.143

emissions were augmented with gridded 2005 emissions from the previous modeling efforts for the rule called “Co ntrol of Emissions from New Marine Compression
- Ignition Engines at or Above 30 Liters per Cylinder”. The 2005 point source daily wildfire and prescribed burning emissions were replaced with average - year county -based inventories. Additionally, the invento ries were processed to provide the hourly, gridded, model
- species needed by CAMx. Tables I V.C - 1 and I V.C - 2 provide summaries of SO 2 and NOX emissions by state by sector for the 2005 base year for those states within the Eastern 12 km modeling domain. Emi ssions for other states within the 36 km modeling domain are available in the EISTD. In the tables, the EGU column summarizes all units matched to the IPM model and the nonEGU column is for other point source units. The Nonpoint column shows emissions fo r all nonpoint stationary sources. The Nonroad column summarizes emissions for nonroad mobile sources, including aircraft, locomotive, and marine sources including the C3 commercial marine. The Onroad column summarizes emissions for the combined NEI and draft MOVES
-based emissions, in which emissions from the draft MOVES were used when available, and NEI emissions based on MOBILE6 were used for the remainder. Finally, the Fires column represents the average
- year fire emissions for wildfires and prescribe d burning mentioned previously.144

Table IV.C - 1. 2005 Base Case SO2 Emissions ( Tons/Year) for Eastern S tates by Sector.
State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Alabama 460,123 70,346 52,325 6,397 3,199 983 593,372 Arkansas 66,384 13,066 27,26 0 5,678 1,632 728 114,749 Connecticut 10,356 1,831 18,455 2,548 1,128 4 34,320 Delaware 32,378 34,859 5,859 11,648 422 6 85,173 District of Columbia 1,082 686 1,559 414 172 0 3,914 Florida 417,321 57,475 70,490 93,543 10,285 7,018 656,131 Georgia 616, 054 56,116 56,829 13,331 5,690 2,010 750,031 Illinois 330,382 156,154 5,395 19,302 5,716 20 516,969 Indiana 878,978 95,200 59,775 9,436 3,981 24 1,047,396 Iowa 130,264 61,241 19,832 8,838 1,702 25 221,902 Kansas 136,520 13,142 36,381 8,035 1,824 103 19 6,005 Kentucky 502,731 25,811 34,229 6,942 2,711 364 572,787 Louisiana 109,851 165,737 2,378 73,233 2,399 892 354,489 Maine 3,887 18,519 9,969 3,725 834 150 37,084 Maryland 283,205 34,988 40,864 17,819 2,966 32 379,874 Massachusetts 85,768 19,620 25,2 61 25,335 2,168 93 158,245 Michigan 349,877 76,510 42,066 14,533 7,204 91 490,280 Minnesota 101,666 25,169 14,747 10,410 2,558 631 155,181 Mississippi 74,117 29,892 6,796 6,003 2,158 1,051 120,016 Missouri 284,384 78,307 44,573 10,464 4,251 186 422,165 Nebraska 74,955 6,429 29,575 9,199 1,326 105 121,589 New Hampshire 51,445 3,245 7,408 805 630 38 63,571 New Jersey 57,044 7,640 10,726 23,484 2,486 61 101,441 New York 180,847 58,562 125,158 20,908 5,628 113 391,216 North Carolina 512,231 66,150 22,0 20 42,743 5,341 696 649,181 North Dakota 137,371 9,458 6,455 5,986 443 66 159,779 Ohio 1,116,084 118,468 19,810 15,615 6,293 22 1,276,292 Pennsylvania 1,002,202 85,411 68,349 11,972 5,363 32 1,173,328 Rhode Island 176 2,743 3,365 2,494 208 1 8,987 Sou th Carolina 218,782 31,495 30,016 20,477 2,976 646 304,393 South Dakota 12,215 1,698 10,347 3,412 511 498 28,682 Tennessee 266,148 78,206 32,714 6,288 4,834 277 388,468 Texas 534,949 223,625 109,215 52,749 13,470 1,178 935,187 Vermont 9 902 5,385 385 3 05 49 7,036 Virginia 220,248 69,440 32,923 18,420 3,829 399 345,259 West Virginia 469,456 48,314 14,589 2,133 1,095 215 535,802 Wisconsin 180,200 66,807 6,369 7,129 3,110 70 263,685 Grand Total 9,909,693 1,913,263 1,109,467 591,832 120,848 18,876 13,66 3,979145

Table IV.C - 2. 2005 Base Case NOX Emissions ( Tons/Year) for Eastern S tates by Sector. State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Alabama 133,051 74,830 32,024 61,623 142,221 3,814 447,562 Arkansas 35,407 37,478 21,453 63,493 81,014 2,6 54 241,499 Connecticut 6,865 5,824 12,554 21,785 69,645 14 116,688 Delaware 11,917 5,567 3,259 15,567 22,569 23 58,902 District of Columbia 492 501 1,740 3,494 9,677 0 15,904 Florida 217,263 53,778 29,533 277,888 460,474 25,600 1,064,537 Georgia 111,0 17 53,297 38,919 95,175 279,449 7,955 585,812 Illinois 127,923 97,504 47,645 223,697 276,507 71 773,347 Indiana 213,503 73,647 30,185 110,100 187,426 88 614,949 Iowa 72,806 39,299 15,150 92,965 91,795 90 312,105 Kansas 90,220 70,785 42,286 86,553 76,06 2 378 366,285 Kentucky 164,743 35,432 17,557 90,669 127,435 1,326 437,163 Louisiana 63,791 165,162 27,559 301,170 112,889 3,254 673,824 Maine 1,100 18,309 7,423 13,379 38,469 566 79,246 Maryland 62,574 24,621 21,715 55,812 129,796 137 294,656 Massachu setts 25,618 18,429 34,373 74,419 118,148 341 271,327 Michigan 120,005 94,139 43,499 101,087 279,816 330 638,876 Minnesota 83,836 64,438 56,700 115,873 146,138 2,300 469,286 Mississippi 45,166 53,985 12,212 79,394 98,060 3,833 292,649 Missouri 127,431 38,604 32,910 123,228 183,022 678 505,873 Nebraska 52,426 12,156 13,820 107,180 58,643 381 244,607 New Hampshire 8,827 3,241 11,235 9,246 32,537 137 65,223 New Jersey 30,114 20,598 26,393 88,486 157,736 223 323,550 New York 63,465 55,122 87,608 121,363 282,072 412 610,042 North Carolina 111,576 44,502 18,869 135,936 225,756 11,424 548,064 North Dakota 76,381 7,545 10,046 59,635 21,575 240 175,422 Ohio 258,687 71,715 41,466 173,988 270,383 81 816,321 Pennsylvania 176,870 89,208 53,435 118,774 266,649 117 705,053 Rhode Island 545 2,164 2,964 7,798 13,456 4 26,930 South Carolina 53,823 29,069 20,281 68,146 128,765 2,357 302,441 South Dakota 15,650 5,035 5,766 30,324 24,850 1,817 83,442 Tennessee 102,934 60,353 18,676 82,331 207,410 1,012 472,717 Te xas 176,170 292,806 274,338 377,246 615,715 4,890 1,741,166 Vermont 297 799 3,438 3,951 13,316 179 21,980 Virginia 62,512 60,101 53,605 91,298 194,173 1,456 463,145 West Virginia 159,804 36,913 14,519 32,739 50,040 785 294,801 Wisconsin 72,170 40,688 2 1,994 75,981 147,952 256 359,042 Grand Total 3,136,980 1,857,64 6 1,207,152 3,591,79 1 5,641,640 79,222 15,514,431 (2) Development of Future Year Emissions146

The future base case scenarios represent predicted emissions in the absence of any further controls beyond those f ederal measures already promulgated. For EGUs, all state and other programs available at the time of modeling have been included. For mobile sources, all national measures available at the time of modeling have been included. For nonEGU p oint and nonpoint stationary sources, any local control programs that may be necessary for areas to attain the annual PM2.5 NAAQS and the ozone NAAQS are not included in the future base case projections. The future base case scenarios do reflect projected economic changes and fuel usage for EGU and mobile sectors, as described in the EITSD. Tables IV.C
- 3 through IV.C
- 6 later provide 2012 and 2014 summaries of emissions data for 2012 and 2014 modeling for all sectors for SO 2 and NOX for states included in t he 12 km modeling domain. The EITSD provides summaries for additional pollutants with additional detail and for all states in the nationwide 36 km modeling domain. Table IV.C - 3. 2012 Base Case SO2 Emissions ( Tons/Year) for

Eastern S tates by Sector.
State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Alabama 335,734 70,346 52,315 2,333 585 983 462,297 Arkansas 85,068 13,054 27,257 818 336 728 127,259 Connecticut 5,493 1,831 18,443 1,292 330 4 27,392 Delaware 7,841 10,974 5,858 14,193 98 6 38,970 Dist rict of Columbia 0 686 1,559 10 41 0 2,296 Florida 228,360 57,491 70,482 102,076 2,072 7,018 467,498 Georgia 552,007 56,122 56,817 7,984 1,253 2,010 676,193147

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Illinois 724,657 133,201 5,384 1,960 1,174 20 866,396 Indiana 829,988 95,201 59,767 871 775 24 986,626 Iowa 169,039 61,242 19,821 482 346 25 250,954 Kansas 59,567 13,048 36,376 518 302 103 109,915 Kentucky 718,980 25,813 34,214 1,368 510 364 781,249 Louisiana 100,239 159,722 2,373 78,051 455 892 341,731 Maine 15,759 18,519 9,950 3,926 156 150 4 8,460 Maryland 49,078 34,988 40,854 17,112 608 32 142,672 Massachusetts 16,299 19,622 25,242 29,825 575 93 91,657 Michigan 287,807 76,458 42,066 7,636 1,074 91 415,132 Minnesota 53,596 25,100 14,733 1,342 596 631 95,997 Mississippi 46,432 24,426 6,788 2,094 375 1,051 81,166 Missouri 445,643 78,310 44,550 1,307 765 186 570,761 Nebraska 120,790 6,430 29,571 817 209 105 157,921 New Hampshire 7,290 3,245 7,396 72 142 38 18,183 New Jersey 37,746 6,747 10,715 25,286 772 61 81,327 New York 144,074 58,566 125,187 12,336 1,541 113 341,818 North Carolina 126,620 66,128 22,000 48,861 935 696 265,240 North Dakota 77,383 9,458 6,451 288 76 66 93,722 Ohio 946,667 105,406 19,810 3,456 1,131 22 1,076,493 Oklahoma 156,032 36,912 7,536 341 502 469 201,791 Penns ylvania 966,136 79,142 68,330 4,938 1,135 32 1,119,712 Rhode Island 0 2,743 3,364 2,879 82 1 9,069 South Carolina 149,515 31,452 30,005 22,697 532 646 234,846 South Dakota 13,453 1,698 10,342 65 91 498 26,147 Tennessee 596,987 77,595 32,701 828 795 277 709,182 Texas 327,873 162,915 109,199 37,109 2,409 1,178 640,682 Vermont 902 5,381 6 94 49 6,432 Virginia 145,452 69,166 32,904 15,158 883 399 263,963 West Virginia 588,392 41,817 14,583 443 197 215 645,646 Wisconsin 107,365 66,452 6,370 928 646 70 181,830 Grand Total 9,243,362 1,802,927 1,116,694 451,705 24,595 19,345 12,658,628 Table IV.C - 4. 2012 Base Case NOX Emissions ( Tons/Year) for Eastern S tates by Sector. State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Alabama 121,809 74,832 31,95 8 49,622 82,135 3,814 364,171 Arkansas 43,222 37,479 21,429 48,349 46,959 2,654 200,092 Connecticut 2,770 5,830 12,475 15,865 37,847 14 74,801 Delaware 4,639 5,567 3,248 15,511 10,700 23 39,687 District of Columbia 2 501 1,739 2,704 4,857 0 9,802 Flor ida 195,673 55,017 29,475 282,147 275,603 25,600 863,515 Georgia 78,011 53,317 38,825 76,901 158,771 7,955 413,780 Illinois 77,920 92,440 47,564 167,046 157,915 71 542,957148

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Indiana 203,107 73,651 30,125 83,760 114,396 88 505,127 Iowa 66,316 39,301 15,06 4 72,031 58,920 90 251,721 Kansas 70,823 70,751 42,249 66,897 43,914 378 295,012 Kentucky 149,179 34,875 17,446 72,289 71,284 1,326 346,399 Louisiana 44,773 161,724 27,525 285,562 64,074 3,254 586,912 Maine 3,139 18,309 7,295 13,354 21,896 566 64,559 Maryland 17,376 24,624 21,647 53,580 64,368 137 181,731 Massachusetts 6,312 18,447 34,245 75,149 57,417 341 191,911 Michigan 96,874 93,953 43,392 80,900 163,505 330 478,955 Minnesota 51,285 64,250 56,581 92,080 86,198 2,300 352,694 Mississippi 37,517 5 2,454 12,151 64,138 52,709 3,833 222,801 Missouri 77,571 38,610 32,731 96,197 108,298 678 354,085 Nebraska 52,820 12,159 13,788 81,177 33,907 381 194,233 New Hampshire 2,514 3,243 11,153 7,308 19,710 137 44,067 New Jersey 15,987 18,996 26,320 81,906 76 ,979 223 220,410 New York 25,755 55,167 87,776 100,212 154,260 412 423,582 North Carolina 61,643 44,514 18,715 133,476 126,081 11,424 395,854 North Dakota 59,547 7,544 10,018 46,649 12,111 240 136,110 Ohio 159,627 69,075 41,378 133,650 149,134 81 552,9 45 Oklahoma 86,858 71,808 94,528 43,057 71,207 1,709 369,167 Pennsylvania 193,032 85,168 53,289 92,594 142,217 117 566,418 Rhode Island 221 2,168 2,959 7,468 8,120 4 20,940 South Carolina 47,762 28,953 20,273 63,564 75,994 2,357 238,903 South Dakota 1 5,493 5,035 5,733 24,117 14,957 1,817 67,151 Tennessee 68,425 59,594 18,573 65,209 126,353 1,012 339,166 Texas 159,738 287,831 274,203 313,204 303,453 4,890 1,343,319 Vermont 800 3,406 3,077 10,328 179 17,790 Virginia 36,036 60,101 53,496 79,717 111,5 83 1,456 342,389 West Virginia 102,725 35,698 14,473 26,040 27,694 785 207,415 Wisconsin 49,351 40,694 21,979 58,951 86,315 256 257,546 Grand Total 2,485,856 1,904,481 1,299,224 3,075,459 3,232,168 80,932 12,078,120
Table IV.C - 5. 2014 Base Case SO2 Emissions ( Tons/Year) for Eastern S tates by Sector.
State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Alabama 322,130 69,150 52,313 1,873 605 983 447,053 Arkansas 88,187 13,055 27,256 142 347 728 129,714 Connecticut 5,512 1,834 18,440 1,294 340 4 27 ,423 Delaware 7,806 10,974 5,857 14,891 101 6 39,635 District of Columbia 0 686 1,559 4 42 0 2,291 Florida 192,903 57,521 70,480 108,579 2,159 7,018 438,658 Georgia 173,210 56,014 56,813 8,263 1,307 2,010 297,618 Illinois 200,475 133,109 5,381 390 1,2 21 20 340,596149

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Indiana 804,294 95,037 59,764 193 810 24 960,123 Iowa 163,966 60,195 19,817 85 360 25 244,448 Kansas 65,125 13,048 36,375 54 313 103 115,018 Kentucky 739,592 23,804 34,210 258 528 364 798,755 Louisiana 94,824 151,216 2,372 78,097 470 892 327,871 Maine 11,650 18,520 9,945 4,215 160 150 44,640 Maryland 42,635 34,994 40,851 16,966 631 32 136,109 Massachusetts 16,299 19,624 25,237 32,043 594 93 93,890 Michigan 275,637 76,437 42,066 7,536 1,107 91 402,874 Minnesota 61,447 25,112 14,728 46 8 618 631 103,005 Mississippi 48,149 24,427 6,785 1,280 385 1,051 82,077 Missouri 500,649 77,086 44,543 214 796 186 623,473 Nebraska 115,695 6,431 29,570 55 217 105 152,072 New Hampshire 6,608 3,246 7,393 45 148 38 17,476 New Jersey 37,669 6,756 10,71 2 26,589 799 61 82,585 New York 141,354 58,584 125,196 10,853 1,594 113 337,694 North Carolina 140,585 66,046 21,994 52,897 961 696 283,180 North Dakota 80,320 9,458 5,763 35 78 66 95,720 Ohio 841,194 105,123 19,810 2,085 1,171 22 969,405 Oklahoma 165 ,773 36,924 7,534 45 524 469 211,268 Pennsylvania 972,977 76,256 68,324 4,117 1,169 32 1,122,876 Rhode Island 0 2,745 3,364 3,128 85 1 9,323 South Carolina 156,096 31,453 30,002 24,380 551 646 243,129 South Dakota 13,459 1,699 10,298 22 94 498 26,070 Tennessee 600,066 77,605 32,696 173 829 277 711,647 Texas 373,950 155,720 109,194 36,109 2,511 1,178 678,662 Vermont 903 5,380 7 101 49 6,439 Virginia 135,741 69,177 32,899 15,624 918 399 254,758 West Virginia 496,307 41,817 14,581 96 201 215 553,218 Wisconsin 117,253 66,456 6,370 638 675 70 191,461 Grand Total 8,209,536 1,778,244 1,116,600 453,742 25,516 19,345 11,602,982
Table IV.C - 6. 2014 Base Case NOX Emissions ( Tons/Year) for

Eastern S tates by Sector.
State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Alabama 118,420 74,622 31,939 45,932 67,011 3,814 341,738 Arkansas 44,792 37,491 21,422 44,299 38,965 2,654 189,623 Connecticut 2,821 5,854 12,451 14,410 31,534 14 67,084 Delaware 4,513 5,567 3,245 15,270 8,736 23 37,353 District of Columbia 1 501 1,738 2,398 3,929 0 8,568 Florida 180,801 55,343 29,457 278,920 225,478 25,600 795,599 Georgia 48,091 53,557 38,797 71,011 130,240 7,955 349,650 Illinois 80,228 93,059 47,540 151,373 131,403 71 503,676150

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total Indiana 200,899 73,523 30,107 76,024 94 ,217 88 474,858 Iowa 68,146 38,831 15,038 65,751 48,836 90 236,692 Kansas 78,920 70,730 42,238 61,613 35,950 378 289,829 Kentucky 148,509 34,979 17,413 65,805 57,759 1,326 325,791 Louisiana 45,457 161,766 27,515 274,697 52,360 3,254 565,049 Maine 2,53 5 18,316 7,257 13,169 18,061 566 59,903 Maryland 19,990 24,687 21,626 52,501 53,040 137 171,980 Massachusetts 6,619 18,527 34,207 75,654 46,748 341 182,095 Michigan 97,455 94,079 43,360 73,939 135,806 330 444,969 Minnesota 51,859 64,372 56,545 84,040 7 1,161 2,300 330,278 Mississippi 37,142 52,440 12,133 58,559 42,525 3,833 206,633 Missouri 82,979 38,744 32,677 88,233 90,001 678 333,312 Nebraska 52,970 12,173 13,779 75,252 27,856 381 182,410 New Hampshire 2,515 3,255 11,129 6,587 16,260 137 39,884 New Jersey 16,268 19,089 26,298 78,875 63,254 223 204,007 New York 28,350 55,359 87,826 92,841 129,376 412 394,165 North Carolina 61,747 44,573 18,669 133,455 104,150 11,424 374,018 North Dakota 59,556 7,549 3,969 42,972 9,925 240 130,252 Ohio 164,945 6 9,157 41,352 120,900 122,426 81 518,861 Oklahoma 81,122 72,525 94,513 39,539 58,382 1,709 347,790 Pennsylvania 196,151 84,111 53,246 83,885 118,122 117 535,631 Rhode Island 281 2,186 2,957 7,384 6,772 4 19,585 South Carolina 47,512 28,969 20,271 62,400 62,996 2,357 224,505 South Dakota 15,514 5,039 5,157 22,021 12,254 1,817 62,368 Tennessee 68,779 59,694 18,542 59,145 104,711 1,012 311,882 Texas 166,177 282,509 274,163 289,605 241,009 4,890 1,258,354 Vermont 803 3,397 2,771 8,563 179 15,713 Virgin ia 32,115 60,216 53,464 75,461 92,291 1,456 315,002 West Virginia 100,103 35,700 14,459 23,798 22,863 785 197,708 Wisconsin 53,774 40,729 21,974 53,848 71,163 256 241,743 Grand Total 2,468,057 1,900,624 1,298,473 2,884,338 2,656,134 80,932 11,288,558 Development of Future
- Year Emissions Inventories for Electric Generating Units Future year 2012 and 2014 b ase c ase EGU emissions used for the air quality modeling runs that predicted ozone and PM2.5 were obtained from version 3.02 EISA of the IPM ( http:// www.epa.gov/airmarkt/progsregs/epa

- ipm/index.html ). The151

IPM is a multiregional, dynamic, deterministic linear programming model of the U.S. electric power sector; version 3.02 EISA features an updated Title IV SO 2 allowance bank assumption, reflects state rules and consent decrees through February 3, 2009, and incorporates updates related to the Energy Independence and Security Act of 2007. Units with advanced controls (e.g., scrubber, SCR) that were not required to run for compliance with Title IV, New S ource Review (NSR), state settlements, or state
- specific rules were allowed in IPM to decide on the basis of economic efficiency whether to operate those controls. Further details on the EGU emissions inventory used for this proposal can be found in the E lectric Generation Modeling Technical Support Document (EGMTSD). Also note that as explained in section IV.A.3, the baseline used in this analysis assumes no CAIR. If EPA’s base case analysis were to assume that reductions from CAIR would continue indefi nitely, areas that are in attainment solely due to controls required by CAIR would again face nonattainment problems because the existing protection from upwind pollution would not be replaced. As explained in that section, EPA believes that this is the most appropriate baseline to use for purposes of determining whether an upwind state has an impact on a downwind monitoring site in violation of section 110(a)(2)(D).152

Development of Future
- Year Emissions Inventories for Mobile Inventories Mobile source inve ntories of onroad and nonroad mobile emissions were created for 2012 and 2015 using a combination of the NMIM and draft MOVES models. Mobile source emissions were further interpolated between 2012 and 2015 to estimate 2014 emissions. Emissions for these years reflect onroad mobile control programs including the Light
- Duty Vehicle Tier 2 Rule, the Onroad Heavy
- Duty Rule, and the Mobile Source Air Toxics (MSAT) final rule. Nonroad mobile emissions reductions for these years include reductions to locomotive s, various nonroad engines including diesel engines and various marine engine types, fuel sulfur content, and evaporative emissions standards. A more comprehensive list of control programs included for mobile sources is available in the EITSD. The onroad emissions were primarily based on the NMIM monthly, county, process level emissions. For both 2012 and 2015, emissions from onroad gasoline sources were augmented with emissions based on the same preliminary version of MOVES as was used for 2005. MOVES
-b ased emissions were computed for CO, NO X , VOC, PM2.5 , and PM 10 . The same MOVES
-based PM2.5 temperature adjustment factors were also applied as in 2005. Nonroad mobile emissions were created only with NMIM using a consistent approach as was used for 2005, but emissions were153

calculated using NMIM future
- year equipment population estimates and control programs for 2012 and 2014. Emissions from 2012 and 2015 were used for locomotives and category 1 and 2 (C1 and C2) commercial marine vessels, based on emissio ns published in OTAQ’s Locomotive Marine Rule, Regulatory Impact Assessment, Chapter 3. For category 3 (C3) commercial marine vessels, a coordination strategy of emissions reductions is ongoing that includes NO X , VOC, and CO reductions for new C3 engines as early as 2011 and fuel sulfur limits that could go into affect as early as 2012. However, given the uncertainty about the timing for parts of these emissions reductions and the fact that the 2012 modeling was conducted well in advance of the December 2 009 publication of the rule, we have not used the controlled emissions in modeling supporting this proposal. Development of Future
- Year Emissions Inventories for Other Inventory Sources Other inventory sources include nonEGU point sources, stationary nonp oint sources, and emissions in Canada and Mexico. Emissions from Canada and Mexico for all source sectors (including EGUs) in these countries were held constant for all cases. This approach reflects the unavailability of future
- year emissions from Canada and Mexico for the future years of interest in time to support the modeling for this proposal.154

The future year emissions for other sectors are described next. For all sector projections, EPA seeks comment on growth and control approaches, particularly wh ere a control measure has not been included. The EITSD provides more details on these projections for additional review and we have included in the EITSD a table for the public to provide more detailed control data to EPA. For nonEGU point sources, emissi ons were projected by including emissions reductions and increases from a variety of sources. For nonEGUs, emissions were not grown using economic growth projections and emissions reductions were applied through plant closures, refinery and other consent decrees, and reductions stemming from several MACT standards. Since aircraft at airports were treated as point emissions sources in the 2005 NEI v2, we also applied projection factors based on activity growth projected by the Federal Aviation Administrati on Terminal Area Forecast (TAF) system, published December 2008. Controls from the NO X SIP call were assumed to have been implemented by 2005 and captured in the 2005 NEI v2. For stationary nonpoint sources, refueling emissions were projected using the re fueling results from the NMIM runs performed for the onroad mobile sector. Portable fuel container emissions were projected using estimates from previous OTAQ rulemaking inventories. Emissions of ammonia and dust from155

animal operations were projected bas ed on animal population data from the Department of Agriculture and EPA. Residential wood combustion was projected by replacement of obsolete woodstoves with new woodstoves and a 1 percent annual increase in fireplaces. Landfill emissions were projected using MACT controls. All other nonpoint sources were held constant between 2005 and the future years. (3) Preparation of Emissions for AQ Modeling The annual and summer day emissions inventory files were processed through the Sparse Matrix Operator Kernel Emissions (SMOKE) Modeling System version 2.6 to produce the gridded model
- ready emissions for input to CAMx. Emissions processing using SMOKE was performed to create the hourly, gridded data of CAMx species required for air quality modeling for all sect ors, including biogenic emissions. Additional information on the development of the emissions data sets for modeling is provided in the EITSD Details about preparation of emissions for contribution modeling are described in the Transport Rule AQ Modeling TSD. c. Preparation of Meteorological and Other Air Quality Modeling Inputs The gridded meteorological input data for the entire year of 2005 were derived from simulations of the Pennsylvania State University/National Center for Atmospheric Research Mesos cale156

Model. This model, commonly referred to as MM5, is a limited
area, nonhydrostatic, terrain
- following system that solves for the full set of physical and thermodynamic equations which govern atmospheric motions. 26 The meteorological outputs from MM5 were processed to create model
- ready inputs for CMAQ using the MM5
- to - CAMx preprocessor (ref CAMx user’s guide). The 2005 MM5 meteorological predictions for selected variables were compared to measurements as part of several performance evaluations of the p redicted data. The evaluation approach included a combination of qualitative and quantitative analyses to assess the adequacy of the MM5 simulated fields. The qualitative aspects involved comparisons of the model
estimated synoptic patterns against observed patterns from historical weather chart archives. Additionally, the evaluations compared spatial patterns of monthly average rainfall and monthly maximum planetary boundary layer (PBL) heights. The operational evaluation included statistical compariso ns of model/observed pairs (e.g., mean normalized bias, mean normalized error, index of agreement, root mean square errors, etc.) for multiple meteorological parameters. For this

26 Grell, G., J. Dudhia, and D. Stauf fer, 1994: A Description of the Fifth
- Generation Penn State/NCAR Mesoscale Model (MM5), NCAR/TN

- 398+STR., 138 pp, National Center for Atmospheric Research, Boulder CO.157

portion of the evaluation, five meteorological parameters were investigated: temperature, humidity, shortwave downward radiation, wind speed, and wind direction. The three individual MM5 evaluations are described elsewhere. 27 , 28 , 29 It was ultimately determined that the bias and error values associated with the 2005 meteorological data were generally within the range of past meteorological modeling results that have been used for air quality applications. Additional details on the meteorological inputs can be found in the AQMTSD. As noted previously , the CAMx simulations for this pr oposal were performed using a spatial resolution of 12 x 12 km. The concentrations of pollutants transported into this Eastern U.S. modeling region were obtained from air quality model simulations performed at coarser 36 x 36 km resolution for a modeling domain covering the lower 48 states and portions of northern Mexico and southern Canada. The 12 x 12 km model simulations were also initialized with air quality predictions from the coarse scale

27 Baker K. and P. Dolwick. Meteorological Modeling Performance Evaluation for the Annu al 2005 Eastern U.S. 12
- km Domain Simulation, USEPA/OAQPS, February 2, 2009. 28 Baker K. and P. Dolwick. Meteorological Modeling Performance Evaluation for the Annual 2005 Western U.S. 12
- km Domain Simulation, USEPA/OAQPS, February 2, 2009. 29 Baker K. and P. Dolwick. Meteorological Modeling Performance Evaluation for the Annual 2005 Continental U.S. 36
- km Domain Simulation, USEPA/OAQPS, February 2, 2009.158

modeling. Pollutant concentrations at the boundaries of the coarse scale modeling domain were obtained from a three
dimensional global atmospheric chemistry model, the GEOSChem30 model (standard version 7
- 04
- 11 31 ). The global GEOSChem model simulates atmospheric chemical and physical processes driven by assimilated meteorological observations from the NASA’s Goddard Earth Observing System (GEOS). This model was run for 2005 with a grid resolution of 2.0 degree x 2.5 degree (latitude
longitude). The predictions were used to provide one
- way dynamic boundary conditio ns at three
- hour intervals and an initial concentration field for the coarse scale simulations. d. Model Performance Evaluation for Ozone and PM2.5 The 2005 base year model predictions for ozone and fine particulate sulfate, nitrate, organic carbon, elemental carbon, and crustal material were compared to measured concentrations in order to evaluate the performance of the modeling platform for replicating observed concentrations. This evaluation was comprised principally of statistical assessments of pair ed

30 Yantosca, B., 2004. GEOS
- CHEMv7
- 01
- 02 User’s Guide, Atmospheric Chemistry Modeling Group, Harvard Un iversity, Cambridge, MA, October 15, 2004.

31 Henze, D.K., J.H. Seinfeld, N.L. Ng, J.H. Kroll, T -M. Fu, D.J. Jacob, C.L. Heald, 2008. Global modeling of secondary organic aerosol formation from aromatic hydrocarbons: high
- vs. low
yield pathways. Atmos. Chem. Phys ., 8, 2405
- 2420.159

modeled and observed data. Details on the evaluation methodology and the calculation of performance statistics are provided in the AQMTSD. The results indicate that, overall, the predicted patterns and day
- to - day variations in regional ozone levels ar e similar to what was observed with measured data. The normalized mean bias for 8
- hour daily maximum ozone concentrations was 17.6 percent and the normalized mean error was 24.8 percent for the months of June through August 2005, based on an aggregate of all observed
-predicted pairs within the 12 km modeling domain. The two PM2.5 species that are most relevant for this proposal are sulfate and nitrate. For the summer months of June though August, when observed sulfate concentrations are highest in the Ea st, the model predictions of 24
- hour average sulfate were lower than the corresponding measured values by 7 percent at urban sites and by 8 to 10 percent at rural sites in the IMPROVE 32 and CASTNET 33 monitoring networks, respectively. For the winter months of December through February, when observed nitrate concentrations are highest in the East, the model predictions of 24
- hour average

32 I nteragency Monitoring of PRO tected Visual E nvironments (IMPROVE). Debell, L.J., et. al. Spatial and Seasonal Patterns and Temporal Variability of Haze and its Constituents in the United States: Report IV. November 2006. 33 Cle an Air Status and Trends Network (CASTNET ) 2005 Annual Report. EPA Office of Air and Radiation, Clean Air Markets Division. Washington, DC. December 2006.160

particulate nitrate were lower than the corresponding measured values by 12 percent at urban sites and by 4 percent at rura l sites in the IMPROVE monitoring network. The model performance statistics by season for ozone and PM2.5 component species are provided in the AQMTSD. 2. How did EPA p roject future n onattainment and maintenance for
annual PM2.5 , 25
- Hour PM2.5 , and 8
- h our o zone? In this section we describe the approach for projecting future concentrations of ozone and PM2.5 to identify locations that are expected to be nonattainment or have a maintenance problem in 2012. The nonattainment and maintenance locations are ba sed on projections of future air quality at existing ozone and PM2.5 monitoring sites. These sites are used as the “receptors” for quantifying the contributions of emissions in upwind states to nonattainment and maintenance in downwind locations. For thi s analysis we are using the air quality modeling results in a “relative” sense to project future concentrations. In this approach, the ratio of future year model predictions to base year model predictions are used to adjust ambient measured data up or down depending in the relative (percent) change in model predictions for each location. a. How did EPA p rocess ambient o zone and PM2.5 data for the purpose of p rojecting future year c oncentrations?161

In this analysis we use measurements of ambient ozone and PM2.5 data that come from monitoring networks consisting of more than one thousand ozone monitors and one thousand PM2.5 monitors located across the country. The monitors are sited according to the spatial and temporal nature of ozone and PM2.5 , and to best represent the actual air quality in the United States. The ambient data used in this analysis were obtained from EPA’s Air Quality System (AQS). In order to use the ambient data, the raw measurements must be processed into a form pertinent for useful int erpretations. For this action, the ozone data were processed consistent with the formats associated with the NAAQS for ozone. The resulting estimates are used to indicate the level of air quality relative to the NAAQS. For ozone air quality indicators, we developed estimates for the 1997 8
- hour ozone standard. The level of the 1997 8
- hour O3 NAAQS is 0.08 ppm. The 8
- hour ozone standard is not met if the 3
- year average of the annual 4th highest daily maximum 8
- hour O3 concentration is greater than 0.08 ppm (0.085 ppm when rounded up). This 3
- year average is referred to as the design value. The PM2.5 ambient data were processed consistent with the formats associated with the NAAQS for PM2.5 . The resulting estimates are used to indicate the level of ai r quality relative to the NAAQS. For PM2.5 , we evaluated concentrations of both the162

annual average PM2.5 NAAQS and the 24
- hour PM2.5 NAAQS. The annual PM2.5 standard is met when the 3
- year average of the annual mean concentration is 15.0 μg/m3 or less. The 3
- year average annual mean concentration is computed at each site by averaging the daily Federal Reference Method (FRM) samples by quarter, averaging these quarterly averages to obtain an annual average, and then averaging the three annual averages. T he 3
- year average annual mean concentration is referred to as the annual design value. The 24
- hour average standard is met when the 3
- year average of the annual 98 th percentile PM2.5 concentration is 35 μg/m3 or less. The 3
- year average mean 98 th percenti le concentration is computed at each site by averaging the 3 individual annual 98 th percentile values at each site. The 3
- year average 98 th percentile concentration is referred to as the 24
- hour average design value. As described later , the approach for p rojecting future ozone and PM2.5 design values involved the projection of an average of up to 3 design value periods which include the years 2003
- 2007 (design values for 2003
- 2005, 2004
- 2006, and 2005
- 2007). The average of the 3 design values creates a “5
- year weighted average” value. The 5
- year weighted average values were then projected to the future years that were analyzed for this proposed rule. The 2003

– 2005, 2004
- 2006, and 2005
- 2007163

design values are accessible at www.epa.gov/airtrends/values.html . The procedures for projecting annual average PM2.5 and 8
- hour ozone were very similar to the methodology used in CAIR. However, the CAIR final rule was promulgated before the most recent versio n of the attainment demonstration modeling guidance was finalized 34 . The procedures for the proposed rule conform to the methodology contained in the final modeling guidance. In the CAIR analysis, EPA did not project 24
- hour PM2.5 design values 35 . The ana lysis for this proposed rule, in contrast, uses the 24
- hour PM2.5 methodology outlined in the modeling guidance. b. Projection of Future Annual and 24
- Hour PM2.5 Nonattainment and Maintenance Annual PM2.5 modeling was performed for the 2005 base year emiss ions and for the 2012 base case as part of the approach for projecting which locations (i.e., monitoring sites) are expected to be in nonattainment and/or have difficulty maintaining the

34 U.S. EPA, 2007: Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5 , and Regional Haze; Office of Air Quality Planning and Standards, Research Triangle Park, NC. 35 CAIR was promulgated in 2005 before the 35 ug/m3 PM2.5 NAAQS was finalized in 2006. Since there were no violations in the eas tern United States (base or future year) of the 1997 65 ug/m3 NAAQS, it was not necessary to project 24 PM2.5 values as part of the modeling for CAIR.164

PM2.5 standards in 2012. We refer to these areas as nonattainment si tes and maintenance sites respectively. In general, the projection methodology involves using the model in a relative sense to estimate the change in PM2.5 between 2005 and the future 2012 base case as recommended in the modeling guidance. Rather than u se the absolute model
-predicted future year ozone and PM2.5 concentrations, the base year and future year predictions are used to calculate a (relative) percent change in ozone and PM2.5 concentrations. For a particular location, the percent change in modeled concentration is multiplied by the corresponding observed base period ambient concentration to estimate the future year design value for that location. The use of observed ambient data as part of the calculation helps to constrain the future year des ign value predictions, even if the absolute model concentrations are over
predicted or under
-predicted. Concentrations of PM2.5 in 2012 were estimated by applying the 2005 to 2012 relative change in model
-predicted PM2.5 species to the (2003
- 2007) PM2 .5 design values. The choice of base period design values is consistent with EPA’s modeling guidance which recommends using the average of the three design value periods centered about the emissions projection year. Since 2005 was the base emissions year , we used the design value for 2003
- 2005, 2004
- 2006, and 2005
- 2007 to represent the base period165

PM2.5 concentrations. For each FRM PM2.5 monitoring site, all valid design values (up to 3) from this period were averaged together. Since 2005 is included in all three design value periods, this has the effect of creating a 5
- year weighted average, where the middle year is weighted 3 times, the 2 nd and 4 th years are weighted twice, and the 1 st and 5 th years are weighted once. We refer to this as the 5
- year we ighted average concentration. The 5
- year weighted average concentrations were used to project concentrations for the 2012 base case in order to determine which monitoring sites are expected to be nonattainment in this future year. We projected 2012 design values for each of 3 year periods (i.e., 2003
- 2005, 2004
- 2006, and 2003
- 2007) and used the highest of these projections to determine which sites are expected to have maintenance problems in 2012. For the analysis of both nonattainment and maintenance,
mon itoring sites were included in the analysis if they had at least one complete design value in the 2003
- 2007 period . 36 There were 721 monitoring sites in the 12 km modeling domain which had at least one complete design value period for the annual PM2.5

36 If there is only one complete design value, then the nonattainment and maintenance design values are t he same.166

NAAQ S, and 736 sites which met this criteria for the 24
- hour NAAQS 37
. EPA followed the procedures recommended in the modeling guidance for projecting PM2.5 by projecting individual PM2.5 component species and then summing these to calculate the concentration of total PM2.5 . The model predictions are used in a relative sense to estimate changes expected to occur in each of the major PM2.5 species. The PM2.5 species are sulfate, nitrate, ammonium, particle bound water, elemental carbon, salt, other primary PM2.5 , and organic aerosol mass by difference. Organic aerosol mass by difference is defined as the difference between FRM PM2.5 and the sum of the other components. The procedure for calculating future year PM2.5 design values is called the SMAT. The SMAT approach is codified in a software tool available from EPA called MATS. The software (including documentation) is available at : http://www.epa.gov/scram001/modelingapps_mats.htm . (1) Methodology for Projecting Future Annual PM2.5 Nonattainment and Maintenance

37 Design values were only used if they were deemed to be officially complete based on CFR 40 Part 50 Appendix N. The completeness criteria for the annual and 24
- hour PM2.5 NAAQS are different. Therefore, there are fewer complete sites for the annual NAAQS.167

The following is a brief summary of the future year annual PM2.5 calculations. Additional details are provided in the modeling guidance, MATS documentation, and the AQMTSD. We are usin g the base period (i.e., 2003

– 2007) FRM data for projecting future design values since these data are used to determine attainment status. In order to apply SMAT to the FRM data, information on PM2.5 speciation is needed for the location of each FRM mon itoring site. Since co
- located PM2.5 speciation data are only available at ~15 percent of FRM monitoring sites, spatial interpolation techniques are used to calculate species concentrations for each FRM monitoring site. Speciation data from the IMPROVE and Speciation Trends Network (STN) were interpolated to each FRM monitor location using the Voronoi Neighbor Averaging (VNA) technique (using MATS). Additional information on the VNA interpolation techniques and data handling procedures can be found in t he MATS User’s Guide. After the species fractions are calculated for each FRM site, the following procedures were used to estimate future year design values: Step 1 : Calculate quarterly mean concentrations for each of the major species components of PM2.5 (i.e., sulfate, nitrate, ammonium, elemental carbon, organic carbon mass, particle bound water, salt, and blank mass). This is done by multiplying the monitored quarterly mean concentration of FRM
- derived total PM2.5168

by the monitored fractional compositi on of PM2.5 species for each quarter averaged over 3 years 38 (e.g., 20 percent sulfate fraction multiplied by 15 μg/m3 PM2.5 equals 3 μg/m3 sulfate). Step 2 : For each quarter, calculate the ratio of future year to base year model predictions for each of th e component species 39 . The result is a set of species
- specific relative response factors (RRF) (e.g., assume that the model
-predicted 2005 base year sulfate for a particular location is 10.0 μg/m3 and the 2012 future concentration is 8.0 μg/m3 , then RRF fo r sulfate is 0.8). The RRFs are calculated based on the modeled concentrations averaged over the nine grid cells 40 centered at the location of the monitor. Step 3 : For each quarter and each of the species, multiply the base year quarterly mean component co ncentration (Step 1) by the species
- specific RRF obtained in Step 2. This results in an estimated future year quarterly mean concentration for each

38 For this analysis, species fractions were calculated using an average of FRM and speciation data for the 2004
- 2006 time period. This was deemed to be representative of the 2005 base year. 39 We did not explicitly model salt and therefo re the salt concentration was held constant from the base to future. Also, blank mass was assumed to be a constant mass of 0.5 ug/m3 in both the base and future years. 40 The modeling guidance recommends calculating annual PM2.5 RRFs using a 3 X 3 grid c ell array (9 grid cells) for a model resolution of 12km.169

species (e.g., 3 μg/m3 sulfate multiplied by 0.8 equals a future sulfate concentration of 2.4 μg/m3 ). Step 4 : Average the four quarterly mean future concentrations to obtain the future year annual design value concentration for each of the component species. Sum the species concentrations to obtain the future year annual average design value for PM2.5 . Step 5 : Calculate the maximum future design value by processing each of the three base design value periods (2003
- 2005, 2004
- 2006, and 2005
- 2007) separately. The highest of the three future values is the maximum design value. The maximum design values are used to determine future year maintenance sites. The preceding procedures for determining future year PM2.5 concentrations were applied for each FRM site. The calculated annual PM2.5 design values are truncated (i.e . , discarded) after the second decimal place 41 . This is consistent with the truncation and rounding procedures for the annual PM2.5 NAAQS. Any value that is greater than or equal to 15.05 μg/m3 is rounded to 15.1 μg/m3 and is considered to be violating the NAAQS. Thus, sites with future year annua l PM2.5 design values of 15.05 μg/m3 or greater, based on the projection of 5
- year weighted average
41 For example, a calculated annual average concentration of 14.94753... becomes 14.94 when digits beyond two places to the right are truncated.170

concentrations, are predicted to be nonattainment sites. Sites with future year maximum design values of 15.05 μg/m3 or greater are predicted to be mainten ance sites. Note that nonattainment sites are also maintenance sites because the maximum design value is always greater than or equal to the 5
- year weighted average. For ease of reference we use the term “nonattainment sites” to refer to those sites that are projected to exceed the NAAQS based on both the average and maximum design values. Those sites that are projected to be attainment based on the average design value but exceed the NAAQS based on the maximum design value are referred to as maintenance sites. The monitoring sites that we project to be nonattainment and/or maintenance for the annual PM2.5 NAAQS in the 2012 base case are the nonattainment/maintenance receptors used for assessing the contribution of emissions in upwind states to downwind nonattainment and maintenance of the annual PM2.5 NAAQS as part of this proposal. Table IV.C
- 7 contains the 2003
- 2007 base c ase period average and maximum annual PM2.5 design values and the corresponding 2012 base case average and maximum design values for sites projected to be nonattainment of the annual PM2.5 NAAQS in 2012. Table IV.C
- 8 contains this same information for projected 2012 maintenance sites.171

Table IV.C - 7. Average and Maximum 2003 - 2007 and 2012 Base Case Annual PM2.5 Design Values (μg/m3 ) at Projected Nonattainment S ites. Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Average

Design Value 2012 Maximum

Design Value 2012

10730023 Alabama Jefferson 18.48 18.67 17.15 17.33 10732003 Alabama Jefferson 17.07 17.45 15.99 16.35 130210007 Georgia Bibb 16.47 16.78 15.33 15.62 130630091 Georgia Clayton 16.47 16.71 15.07 15.29 131210039 Georgia Fulton 17.43 17.47 16.01 16.04 170310052 Illinois Cook 15.75 16.02 15.16 15.43 171191007 Illinois Madison 16.72 17.01 16.56 16.85 171630010 Illinois Saint Clair 15.58 15.74 15.48 15.63 180190006 Indiana Clark 16.40 16.60 15.96 16.16 180372001 Indiana Dubois 15.18 15.68 15.07 15.57 180970078 Indiana Marion 15.26 15.43 15.18 15.36 180970081 Indiana Marion 16.05 16.36 15.93 16.25 180970083 Indiana Marion 15.90 16.27 15.77 16.15 211110043 Kentucky Jefferson 15.53 15.75 15.19 15.41 261630015 Michigan Wayne 15.88 16.40 15.05 15.55 261630033 Michigan Wayne 17.50 18.16 16.57 17.19 390170016 Ohio Butler 15.74 16.11 15.25 15.61 390350038 Ohio Cuyahoga 17.37 18.1 16.26 16.95 390350045 Ohio Cuyahoga 16.47 16.98 15.42 15.91 390350060 Ohio Cuyahoga 17.11 17.66 16.02 16.55 390610014 Ohio Hamilton 17.29 17.53 16.69 16.93 390610042 Ohio Hamilton 16.85 17.25 16.33 16.71 3906 10043 Ohio Hamilton 15.55 15.82 15.05 15.32 390617001 Ohio Hamilton 16.17 16.56 15.65 16.03 390618001 Ohio Hamilton 17.54 17.90 16.93 17.27 420030064 Pennsylv

ania Allegheny 20.31 20.75 18.90 19.31 420031301 Pennsylv

ania Allegheny 16.26 16.57 15.13 15.4 2 420070014 Pennsylv

ania Beaver 16.38 16.45 15.23 15.30 420710007 Pennsylv

ania Lancaster 16.55 17.46 15.19 16.01 421330008 Pennsylv

ania York 16.52 17.25 15.25 15.94 540110006 West

Virginia Cabell 16.30 16.57 15.25 15.50 540391005 West

Virginia Kanawha 16.52 16.59 15.28 15.34172

Table IV.C - 8. Average and Maximum 2003 - 2007 and 2012 Base Case Annual PM2.5 Design Values (μg/m3 ) at Projected Maintenance -Only S ites. Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Average

Design Value 2012 Maximum

Design Value 2012

170313301 Illinois Cook 15.24 15.59 14.73 15.06 170316005 Illinois Cook 15.48 16.07 14.92 15.48 211110044 Kentucky Jefferson 15.31 15.47 14.93 15.09 360610056 New York New York 16.18 17.02 14.98 15.74 3903 50027 Ohio Cuyahoga 15.46 16.13 14.50 15.13 390350065 Ohio Cuyahoga 15.97 16.44 14.96 15.40 390610040 Ohio Hamilton 15.50 15.88 15.03 15.40 390811001 Ohio Jefferson 16.51 17.17 14.95 15.54 391130032 Ohio Montgomer y 15.54 15.92 15.01 15.37 391510017 Oh io Stark 16.15 16.59 14.99 15.40 420110011 Pennsylv

ania Berks 15.82 16.19 14.77 15.11 482011035 Texas Harris 15.42 15.84 14.74 15.14 540030003 West

Virginia Berkeley 15.93 16.19 14.95 15.20 540090005 West

Virginia Brooke 16.52 16.80 14.95 15.22 540291 004 West

Virginia Hancock 15.76 16.64 14.34 15.15 540490006 West

Virginia Marion 15.03 15.25 14.96 15.18
(2) Methodology for Projecting Future 24
- Hour PM2.5 Nonattainment and Maintenance The following is a brief summary of the procedures used for calcul ating future year 24
- hour PM2.5 design values. Additional details are provided in the modeling guidance, MATS documentation, and the AQMTSD. Similar to the annual PM2.5 calculations, we are using the 2003
- 2007 base period FRM data173

for projecting future year design values. The 24
- hour PM2.5 calculations are computationally similar to the annual average calculations. The main difference is that the base period 24
- hour 98 th percentile PM2.5 concentrations are projected to the future year, instead of the an nual average concentrations. Also, the PM2.5 species fractions and relative response factors are calculated from observed and modeled high concentration days, instead of quarterly average data. Both the annual PM2.5 and 24
- hour PM2.5 calculations are per formed on a calendar quarter basis. Since all years and quarters are averaged together in the annual PM2.5 calculations, the individual years can be averaged together early in the calculations. However, in the 24
- hour PM2.5 calculations, only the high qu arter from each year is used in the final calculations. This represents the 98 th percentile value, which can come from any of the 4 quarters in any year. Therefore all quarters and years must be carried through to near the end of the calculations when the individual future year high quarter values are selected. The following are the steps followed for calculating the 2012 base case 24
- hour PM2.5 design values: Step 1 : At each FRM monitoring site, we identify the maximum 24
- hour PM2.5 concentration in each quarter that is less than or equal to the 98th percentile value over the entire year.174

This results in a data set for each year (for up to 5 years) for each site containing one quarter with the observed 98th percentile value and three quarters with the maximum highest values from each quarter that are less than or equal to the 98th percentile value for the year. All 20 quarters (i.e., 4 quarters in each of 5 years) of data are carried through the calculations until the high future year quarter value is i dentified in step 5. Step 2 : In this step we calculate quarterly ambient concentrations on “high” 42 days for each of the major component species of PM2.5 (sulfate, nitrate, ammonium, elemental carbon, organic carbon mass, particle bound water, salt and bl ank mass). This calculation is performed by multiplying the monitored concentrations of FRM
- derived total PM2.5 mass on the 10 percent highest days from each quarter, by the monitored fractional composition of PM2.5 species on the 10 percent highest PM2.5 days for each quarter, averaged over 3 years 43 (e.g., 20 percent sulfate fraction multiplied by 40 μg/m3 PM2.5 equals 8 μg/m3 sulfate).

42 High ambient data and model days were defined as the top 10 percent days in e ach quarter based on 24
- hour concentrations of PM2.5 . 43 For this analysis, species fractions were calculated using an average of FRM and speciation data for the 2004
- 2006 time period. This was deemed to be representative of the 2 005 modeling year.175

Step 3 : For each quarter, we calculate the ratio of future year (i.e., 2012) to base year (i.e., 2005) predictions for each component species 44 for the top 10 percent of days based on predicted concentrations of 24
- hour PM2.5 . The result is a set of species
- specific relative response factors (RRF) for the high PM2.5 days in each quarter (e.g., assume that 2005 predicted
s ulfate on the 10 percent highest PM2.5 days for a quarter for a particular location is 20 μg/m3 and the 2012 base case concentration is 16 μg/m3 , then RRF for sulfate is 0.8). The RRFs are calculated based on the modeled concentrations at the single grid cell where the monitor is located. Step 4 : For each quarter, we multiply the quarterly species concentration (step 2) by the quarterly 45 species
specific RRF obtained in step 3. This leads to an estimated future quarterly concentration for each component . (e.g., 21.0 μg/m3 nitrate x 0.75 = future nitrate of 15.75 μg/m3 ). Step 5 : We sum the species concentrations to obtain quarterly PM2.5 values. This step is repeated for each quarter

44 We did not explicitly model salt and therefore the salt concentration was held constant from the base to future. Also, blank mass was assumed to be a constant mass of 0.5 ug/m3 in both the base and future years. 45 Since there is o nly one modeled base year, there are a single set of four quarterly RRFs. The modeled quarterly RRF for quarter 1 is multiplied by the ambient data for quarter 1 for each of the 5 years of ambient data. The same procedure is applied for the other 3 quart ers.176

and for each of the 5 years of ambient data. The highest daily value (from the 4 quarterly values) for each year at each monitor is considered to be the estimated future year 98th percentile 24
- hour design value for that year. Step 6 : The estimated 98th percentile values for each of the 5 years are averaged over 3 year in tervals to create the 3 year average design values. These design values are averaged to create a 5 year weighted average for each monitoring site. Step 7 : The maximum future design value is calculated by following the previous steps for each of the thre e base design value periods (2003
- 2005, 2004
- 2006, and 2005
- 2007) separately. The highest of the three future values is the maximum design value. This maximum value is used to identify the 24
- hour PM2.5 maintenance receptors.. The preceding procedures fo r determining future year 24
- hour PM2.5 concentrations were applied for each FRM site. The 24
- hour PM2.5 design values are truncated after the first decimal place. This approach is consistent with the truncation and rounding procedures for the 24
- hour PM2.5 NAAQS. Any value that is greater than or equal to 35.5 μg/m3 is rounded to 36 μg/m3 and is violating the NAAQS. Sites with future year 5 year weighted average design values of 35.5 μg/m3 or greater, based on the projection of 5
- year weighted average c oncentrations, are predicted to be nonattainment. Sites with future year maximum177

design values of 35.5 μg/m3 or greater are predicted to be maintenance sites. Note that nonattainment sites for the 24
- hour NAAQS are also maintenance sites because the maximum design value is always greater than or equal to the 5
- year weighted average. For ease of reference we use the term “nonattainment sites” to refer to those sites that are projected to exceed the NAAQS based on both the average and maximum design values . Those sites that are projected to be attainment based on the average design value but exceed the NAAQS based on the maximum design value are referred to as maintenance sites. The monitoring sites that we project to be nonattainment and/or maintenance f or the 24
- hour PM2.5 NAAQS in the 2012 base case are the nonattainment/maintenance receptors used for assessing the contribution of emissions in upwind states to downwind nonattainment and maintenance of 24
- hour PM2.5 NAAQS as part of this proposal. Table IV.C - 9 contains the 2003
- 2007 base period average and maximum 24
- hour PM2.5 design values and the 2012 base case average and maximum design values for sites projected to be 2012 nonattainment of the 24
- hour PM2.5 NAAQS in 2012. Table IV.C
- 10 contains this same information for projected 2012 24
- hour maintenance sites.178

Table IV.C - 9. Average and maximum 2003 - 2007 and 2012 Base Case 24 -Hour PM2.5 Design Values (μg/m3 ) at Projected Nonattainment S ites. Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Average

Design Value 2012 Maximum

Design Value 2012
10730023 Alabama Jefferson 44.0 44.2 40.0 40.7 10732003 Alabama Jefferson 40.3 40.8 38.1 38.9 90091123 Connecti

cut New Haven 38.3 40.3 35.7 36.6 170310052 Illinois Cook 4 0.2 41.4 38.5 39.7 170310057 Illinois Cook 37.3 38.6 35.7 37.0 170310076 Illinois Cook 38.0 39.1 36.3 37.3 170311016 Illinois Cook 43.0 46.3 41.0 44.1 170312001 Illinois Cook 37.7 40.6 35.6 38.2 170313103 Illinois Cook 39.6 40.3 38.1 38.7 170313301 I llinois Cook 40.2 43.3 38.2 41.0 170316005 Illinois Cook 39.1 41.8 37.4 39.8 171190023 Illinois Madison 37.3 38.1 39.4 40.2 171191007 Illinois Madison 39.1 40.1 40.0 40.6 171192009 Illinois Madison 34.9 35.9 37.2 38.2 171193007 Illinois Madison 34.0 3 4.6 36.5 37.3 180190006 Indiana Clark 37.5 39.4 38.1 40.2 180372001 Indiana Dubois 35.3 36.9 36.5 38.0 180830004 Indiana Knox 35.9 36.3 35.9 36.5 180890022 Indiana Lake 38.9 44.0 37.3 42.1 180890026 Indiana Lake 38.4 41.3 36.3 39.3 180970042 Indiana Marion 34.2 35.3 36.3 37.2 180970043 Indiana Marion 38.4 39.9 40.5 42.0 180970066 Indiana Marion 38.3 39.6 40.3 41.8 180970078 Indiana Marion 36.6 37.6 38.7 39.7 180970079 Indiana Marion 35.6 36.7 37.2 38.3 180970081 Indiana Marion 38.2 39.2 40.1 41.1 180970083 Indiana Marion 36.6 37.0 39.0 39.3 181570008 Indiana Tippecanoe 35.6 36.7 35.9 36.9 191630019 Iowa Scott 37.1 37.1 36.8 36.8 210590005 Kentucky Daviess 33.8 33.8 37.0 37.0 211110043 Kentucky Jefferson 35.4 36.1 35.8 36.4 211110044 Kentucky Jefferson 36.1 36.6 36.0 36.5 211110048 Kentucky Jefferson 36.4 37.2 35.6 36.4 245100040 Maryland Baltimore City 39.0 40.9 36.3 38.3 245100049 Maryland Baltimore City 38.1 38.1 35.5 35.5 261150005 Michigan Monroe 38.8 39.6 37.0 38.0 261250001 Michiga n Oakland 39.9 40.4 37.9 38.4179

Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Average

Design Value 2012 Maximum

Design Value 2012
261470005 Michigan St. Clair 39.6 40.6 38.4 39.4 261610008 Michigan Washtenaw 39.4 40.8 38.1 39.8 261630015 Michigan Wayne 40.1 40.6 38.5 39.1 261630016 Michigan Wayne 42.9 45.4 40.6 43.0 261630019 Michigan Wayne 40.9 41. 4 38.6 39.1 261630033 Michigan Wayne 43.8 44.2 42.1 42.6 261630036 Michigan Wayne 37.1 37.9 36.3 36.9 290990012 Missouri Jefferson 33.4 34.2 35.7 36.5 291831002 Missouri Saint Charles 33.1 34.7 35.5 37.1 295100007 Missouri St. Louis City 33.1 33.5 36. 0 36.3 295100087 Missouri St. Louis City 34.3 34.7 36.4 36.9 340171003 New

Jersey Hudson 39.0 40.5 35.7 36.1 340172002 New

Jersey Hudson 41.4 41.4 38.2 38.2 340390004 New

Jersey Union 40.4 41.4 36.7 37.2 360050080 New York Bronx 38.8 40.2 35.9 36.2 3 60610056 New York New York 39.7 40.6 37.1 38.0 360610128 New York New York 39.4 41.8 36.2 38.0 390170003 Ohio Butler 39.2 41.1 40.3 42.3 390170016 Ohio Butler 37.1 37.7 37.5 37.8 390170017 Ohio Butler 37.9 37.9 38.5 38.5 390171004 Ohio Butler 37.1 38. 1 37.8 38.6 390350038 Ohio Cuyahoga 44.2 47.0 41.2 44.0 390350045 Ohio Cuyahoga 38.5 41.5 36.0 39.0 390350060 Ohio Cuyahoga 42.1 45.7 39.4 42.8 390350065 Ohio Cuyahoga 38.6 41.0 36.5 38.9 390490024 Ohio Franklin 38.5 39.7 36.6 37.6 390490025 Ohio Fra nklin 38.4 39.1 36.1 36.4 390610006 Ohio Hamilton 37.6 37.6 38.0 38.0 390610014 Ohio Hamilton 38.2 39.4 37.5 38.5 390610040 Ohio Hamilton 36.7 37.7 35.8 36.8 390610042 Ohio Hamilton 37.3 38.2 37.2 38.0 390610043 Ohio Hamilton 35.9 36.2 36.0 36.4 3906 17001 Ohio Hamilton 38.8 39.6 37.7 38.1 390618001 Ohio Hamilton 40.6 40.9 39.6 40.3 390811001 Ohio Jefferson 41.9 45.5 36.5 39.9 391130032 Ohio Montgomery 37.8 40.0 36.3 38.5 391530017 Ohio Summit 38.0 39.6 35.6 37.2 420030008 Pennsylv

ania Allegheny 3 9.4 39.9 35.9 36.3180

Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Average

Design Value 2012 Maximum

Design Value 2012
420030064 Pennsylv

ania Allegheny 64.2 68.2 58.8 62.3 420030093 Pennsylv

ania Allegheny 45.6 51.5 41.1 46.2 420030116 Pennsylv

ania Allegheny 42.5 42.5 37.1 37.1 420031008 Pennsylv

ania Allegheny 41.3 42.8 38.0 39.3 420031301 Pennsylv

an ia Allegheny 40.3 42.4 36.6 38.6 420070014 Pennsylv

ania Beaver 43.4 44.6 37.7 39.1 420110011 Pennsylv

ania Berks 37.7 39.1 35.8 37.0 420210011 Pennsylv

ania Cambria 39.0 39.4 40.3 40.7 420430401 Pennsylv

ania Dauphin 38.0 39.0 35.7 37.1 420710007 Pennsyl v

ania Lancaster 40.8 44.0 37.7 40.1 421330008 Pennsylv

ania York 38.2 40.7 35.9 38.8 471251009 Tennesse

e Montgomery 36.3 37.5 36.6 37.9 540090011 West

Virginia Brooke 43.9 44.9 39.9 40.8 550790010 Wisconsi

n Milwaukee 38.6 40.0 37.7 39.0 550790026 Wisco nsi

n Milwaukee 37.3 41.3 36.3 40.1 550790043 Wisconsi

n Milwaukee 39.9 40.8 38.8 39.7 550790099 Wisconsi

n Milwaukee 37.7 38.7 36.8 37.7

Table IV.C - 10. Average and Maximum 2003 - 2007 and 2012 Base Case 24 -Hour PM2.5 Design Values (μg/m3 ) at Projected Maintenance -Only S ites.

Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Averag

e Design Value 2012 Maximu

m Design Value 2012 110010041 Washington

D.C. Washington

D.C. 36.3 37.8 34.0 35.6181

Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Averag

e Design Value 2012 Maximu

m Design Value 2012 110010042 Washington

D.C. Washin gton

D.C. 34.9 37.0 33.0 35.6 170310022 Illinois Cook 36.6 38.6 34.9 36.6 170310050 Illinois Cook 36.1 38.0 34.1 35.8 170314007 Illinois Cook 34.3 36.4 33.6 35.7 171630010 Illinois Saint Clair 33.7 34.1 35.3 35.9 171971002 Illinois Will 36.4 37.1 35.1 35.8 180390003 Indiana Elkhart 34.4 36.3 33.8 35.6 180431004 Indiana Floyd 33.2 34.5 34.3 35.7 181670023 Indiana Vigo 34.8 36.1 35.1 36.5 191390015 Iowa Muscatine 36.0 37.7 34.5 36.0 210290006 Kentucky Bullitt 34.6 35.8 35.0 36.3 211451004 Kentucky McCracken 33.6 35.9 34.4 36.8 212270007 Kentucky Warren 33.1 35.1 33.7 36.3 240031003 Maryland Anne Arundel 35.5 37.4 33.8 36.7 245100035 Maryland Baltimore (City) 37.7 39.2 34.7 35.5 261630001 Michigan Wayne 37.8 40.1 35.4 37.8 295100085 Missouri St. Louis City 33.2 33.8 35.3 35.7 360610062 New York New York 38.8 41.6 35.3 37.0 360610079 New York New York 37.9 40.2 34.2 36.4 390350027 Ohio Cuyahoga 36.6 38.8 34.5 36.6 390350034 Ohio Cuyahoga 36.5 37.9 33.7 35.7 390810017 Ohio Jefferson 40.7 42.4 35.3 36.8 390950024 Ohio Lucas 36.3 38.6 34.2 36.5 390950026 Ohio Lucas 34.9 36.7 33.6 35.6 390990014 Ohio Mahoning 36.8 38.2 34.2 35.8 391130031 Ohio Montgomery 35.7 37.1 34.3 35.6 391351001 Ohio Preble 32.8 33.9 34.3 35.5 391550007 Ohio Trumbull 36 .2 37.8 33.9 35.6 420030095 Pennsylvan

ia Allegheny 38.7 40.7 34.3 36.6 420033007 Pennsylvan

ia Allegheny 37.5 43.1 33.8 38.5 420410101 Pennsylvan

ia Cumberland 38.0 40.2 35.3 37.0 421255001 Pennsylvan

ia Washington 38.1 39.9 33.9 35.5 471650007 Tennessee Sumner 33.6 34.5 35.1 36.0 540090005 West

Virginia Brooke 39.4 41.5 33.9 36.1 550250047 Wisconsin Dane 35.5 36.9 35.1 36.1 550790059 Wisconsin Milwaukee 35.5 37.0 34.8 36.3182

Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Averag

e Design Value 2012 Maximu

m Design Value 2012 551330027 Wisconsin Waukesha 35.4 36.2 34.9 35.6 (3) Methodology for Project ing Future 8
- Hour Ozone Nonattainment and Maintenance The following is a brief summary of the future year 8
- hour average ozone calculations. Additional details are provided in the modeling guidance, MATS documentation, and the AQMTSD. We are using the bas e period 2003
- 2007 ambient ozone design value data for projecting future year design values. The ozone projection procedure is relatively simple, since ozone is a single species. It is not necessary to interpolate ambient ozone data, since ambient ozone design values and gridded, modeled ozone is all that is needed for the projections. To project 8
- hour ozone design values we used the 2005 base year and 2012 future base case model
-predicted ozone concentrations to calculate relative response factors. The methodology we followed is consistent with the attainment demonstration modeling guidance. The RRFs were applied to the 2003
- 2007 ozone design values through the following steps: Step 1 : For each monitoring site we calculate the average concentration ac ross all days with 8
- hour daily maximum183

predictions greater than or equal to 85 ppb 46 using the predictions in the nine grid cells that include or surround the location of the monitoring site. The RRF for a site is the ratio of the mean prediction in the future year to the mean prediction in the 2005 base year. The RRFs were calculated on a site
-by
- site basis. Step 2 : The RRF for each site is then multiplied by the 2003
- 2007 5
- year weighted average ambient design value for that site, yielding an estimat e of the future year design value at that particular monitoring location. Step 3 : We calculate the maximum future design value by projecting design values for each of the three base periods (2003
- 2005, 2004
- 2006, and 2005
- 2007) separately. The highest
o f the three future values is the maximum design value. This maximum value is used to identify the 8
- hour ozone maintenance receptors. The preceding procedures for determining future year 8
- hour average ozone design values were applied for each ozone monit oring site. The future year design values are truncated to integers in units of ppb. This approach is consistent with the truncation and rounding procedures for the 8
- hour ozone NAAQS.
46 As specified in the attainment demonstration modeling guidance, if there are less than 10 modeled days > 85 ppb, then the threshold is lowered in 1 ppb increments (to as low as 70 ppb) until there 10 days. If there are less than 5 days > 70 ppb, t hen an RRF calculation is not completed for that site.184

Future year design values that are greater than or equal to 85 ppb a re considered to be violating the NAAQS. Sites with future year 5 year weighted average design values of 85 ppb or greater are predicted to be nonattainment. Sites with future year maximum design values of 85 ppb or greater are predicted to be future yea r maintenance sites. Note that, as described previously for the annual and 24
- hour PM2.5 NAAQS, nonattainment sites for the ozone NAAQS are also maintenance sites because the maximum design value is always greater than or equal to the 5
- year weighted aver age. For ease of reference we use the term “nonattainment sites” to refer to those sites that are projected to exceed the NAAQS based on both the average and maximum design values. Those sites that are projected to be attainment based on the average desi gn value but exceed the NAAQS based on the maximum design value are referred to as maintenance sites. The monitoring sites that we project to be nonattainment and/or maintenance for the ozone NAAQS in the 2012 base case are the nonattainment/maintenance r eceptors used for assessing the contribution of emissions in upwind states to downwind nonattainment and maintenance of ozone NAAQS as part of this proposal. Table IV.C
- 11 contains the 2003
- 2007 base period average and maximum 8
- hour ozone design values an d the 2012 base case average and maximum design values for sites projected to be 2012185

nonattainment of the 8
- hour ozone NAAQS in 2012. Table IV.C
- 12 contains this same information for projected 2012 8
- hour ozone maintenance sites. Table IV.C - 11. Average and Maximum 2003 - 2007 and 2012 Base Case 8 -Hour Ozone Design Values (ppb) at Projected Nonattainment S ites.

Monitor ID State County Average Design Value 2003 - 2007 Maximum

Design Value 2003 - 2007 Average

Design Value 2012 Maximum

Design Value 2012 220330003 Louisiana East Baton Rouge 92 96 87.8 91.6 361030002 New York Suffolk 90 91 86.3 87.2 361030009 New York Suffolk 90.3 91 85.1 85.8 421010024 Pennsylvania Philadelphia 90.3 91 85.3 86 480391004 Texas Brazoria 94.7 97 88.8 91 482010051 Texas Harris 93 98 88.4 93.1 482010055 Texas Harris 100.7 103 95.7 97.9 482010062 Texas Harris 95.7 99 90.5 93.7 482010066 Texas Harris 92.3 96 89.9 93.5 482011039 Texas Harris 96.3 100 90.5 93.9 484391002 Texas Tarrant 93.3 95 85.1 86.7
Table IV.C - 12. Average and Maximum 2003 - 2007 and 2012 Base Case 8 -Hour Ozone Design Values (ppb) at Projected Maintenance -Only S ites. Monitor ID State County Average Design Value 2003
- 2007 Maximum

Design Value 2003
- 2007 Average

Design Value 2012 Maximum

Design Value 2012 90010017 Connecticut Fairfield 88 90 83.1 85 90011123 Connecticut Fairfield 92.3 94 84.8 86.4 90013007 Connecticut Fairfield 90 92 84.5 86.4 90093002 Connecticut New Haven 90.3 93 82.9 85.4 130890002 Georgia DeKalb 88.7 93 81.6 85.6 131210055 Georgia Fulton 9 1.7 94 84.4 86.5 361192004 New York Westchester 87.7 90 84.7 86.9 420170012 Pennsylvania Bucks 88 92 81.8 85.6 481130069 Texas Dallas 87 90 82.9 85.8 481130087 Texas Dallas 87 88 84.6 85.6186

Monitor ID State County Average Design Value 2003
- 2007 Maximum

Design Value 2003
- 2007 Average

Design Value 2012 Maximum

Design Value 2012 482010024 Texas Harris 88 92 83.3 87.1 482010029 Texas Harris 91.7 93 84.4 85.6 482011015 Texas Harris 89 96 83.7 90.3 482011035 Texas Harris 86.3 95 82 90.3 482011050 Texas Harris 89.3 92 83.9 86.5 484392003 Texas Tarrant 93.7 95 84 85.2
3. How did EPA a ssess i nterstate c ontributions to n onattainment and main tenance? This section documents the procedures used by EPA to quantify the impact of emissions in specific upwind states on air quality concentrations in projected downwind nonattainment and maintenance locations for annual PM2.5 , 24
- hour PM2.5 , and 8
- hou r ozone. These procedures are the first of the two
- step approach for determining significant contribution, as described previously in section IV. A.3 . EPA used CAMx photochemical source apportionment modeling to quantify the impact of emissions in specific upwind States on projected downwind nonattainment and maintenance receptors for both PM2.5 and 8
- hour ozone. Details of the modeling techniques and post
-processing procedures are described in this section. CAMx employs enhanced source apportionment techn iques which track the formation and transport of ozone and particulate matter from specific emissions sources and calculates the contribution of sources and precursors to ozone and PM2.5 for187

individual receptor locations. The strength of the photochemical model source apportionment technique is that all modeled ozone and/or PM2.5 mass at a given receptor location in the modeling domain is tracked back to specific sources of emissions and boundary conditions to fully characterize culpable sources. This typ e of emissions apportionment is useful to understand the types of sources or regions that are contributing to ozone and PM2.5 estimated by the model. Source apportionment is an alternative approach to zero
- out modeling 47 and other methods to track pollutant formation in photochemical models. Source apportionment completely characterizes source contributions to model estimated ozone and PM2.5 , which is not possible with an emissions sensitivity approach such as zero
- out, since the change in emissions leads t o changes in pollutant concentrations, meaning the sum of estimated ozone or PM2.5 in all zero
- out simulations may not exactly match the ozone or PM2.5 estimated in the base model simulation. Photochemical model source apportionment has the additional advantage over emissions sensitivity based approaches by being more computationally efficient. There is currently no

47 Zero - out modeling is a technique in which all emissions are removed (e.g. , NO x an d VOC emissions from a particular state) in a model run and then compared to the results of a second model run in which the same emissions have not been removed. The difference between the two model runs represents sensitivity or contribution from the emissions that were removed.188

technical evidence showing that one technique is clearly superior to the other for evaluating contributions to ozone and PM2.5 from various emission sources. However, since source apportionment explicitly tracks the formation and transport of all ozone and PM2.5 mass, it is particularly well suited for quantifying interstate contributions as part of this proposal. More details on the implement ation of photochemical source apportionment in CAMx can be found in the CAMx user’s guide. In the analysis performed for CAIR, EPA conducted zero
- out modeling for PM2.5 , and both zero
- out and source apportionment modeling for ozone. The CAIR modeling was conducted at 36 km resolution for PM2.5 and 12 km resolution for ozone. In contrast, the current analysis was performed at 12 km resolution for both ozone and PM2.5 . When choosing the modeling techniques to use for the Transport Rule, we carefully consi dered all of the pros and cons of each technique, including the lengthy model run times and large file sizes of the 12 km Eastern U.S. modeling domain. Due to the scientific credibility of the source apportionment technique and significant time and resour ce savings compared to zero
- out modeling, we chose to perform the modeled contribution analyses for PM2.5 and ozone with photochemical source apportionment. The EPA performed source apportionment modeling for both ozone and PM2.5 for the 2012 base case emissions. In this189

modeling we tracked the ozone and PM2.5 formed from emissions from sources in each upwind state in the 12 km modeling domain. The results were used to calculate the contributions of these upwind emissions to downwind nonattainment and ma intenance receptors. The states EPA analyzed using source apportionment for ozone and for PM2.5 are: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland, Massachusetts, Michiga n, Minnesota, Mississippi, Missouri, Nebraska, New Hampshire, New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, South Dakota, Tennessee, Texas, Vermont, Virginia, West Virginia, Washington D.C., and Wisconsin. There were also several other states that are only partially contained within the 12 km modeling domain (i.e., Colorado, Montana, New Mexico, and Wyoming). However, EPA did not individually track the emissions or assess the contribution f rom emissions in these states. In contrast to CAIR, all contributions to downwind nonattainment and maintenance receptors for this proposal were calculated using a relative approach. This is similar to the approach used to calculate future year design val ues, as described in section IV.C.2.a. In CAIR we used absolute and relative metrics to examine air quality contributions. Although absolute contributions are useful for certain applications,190

there are advantages of examining the relative contributions f or both ozone and PM2.5 . The main advantage of relative contributions is that they help to minimize biases introduced by model over
-predictions and under
-predictions. Also, the relative approach constrains the total contributions to the measurements of o zone and PM2.5 species concentrations at each downwind receptor. Since model performance is variable across the domain, EPA judged the relative approach to be the most appropriate technique for the Transport Rule. a. Annual and 24
- Hour PM2.5 Contribution Modeling Approach EPA used the CAMx Particulate Source Apportionment Technique (PSAT) to calculate downwind PM2.5 contributions to nonattainment and maintenance. The CAMx PSAT is capable of “tagging” (i.e., tracking) source category emissions for certain PM species and precursor emissions. For this proposal, we ran PSAT to tag emissions of NO X , SO 2 , and primary PM2.5 from the individual states listed previously . Due to small modeled concentrations of secondary organic aerosols (SOA), and the relatively large runtime penalty of the SOA PSAT mechanism, we chose not to track SOA. Through emissions pre
-processing procedures, EPA tagged all of the anthropogenic NO X , SO 2 , and primary PM2.5 emissions in each upwind state. Each state was a separate tag, and the tagged emissions followed state boundaries (not grid cells).191

In the PSAT simulation NO x emissions are tracked to particulate nitrate concentrations, SO 2 emissions are tracked to particulate sulfate concentrations, and primary particulates (organic carb on, elemental carbon, and other PM2.5 ) are tracked as primary particulates. As described earlier in section IV.B., the nitrate and sulfate contributions were combined and used to evaluate interstate contributions of PM2.5 , as described in section IV.C.4, later . We developed and applied several post
-processing steps to transform the PSAT modeling outputs to PM2.5 downwind contributions. The approach involved processing the PSAT model outputs using MATS along with other post
-processing software to calculat e the contribution of each upwind state to each downwind nonattainment and/or maintenance receptor. This process involved calculating a ratio which uses the PSAT
-predicted absolute contribution for each species (e.g., sulfate) coupled with the CAMx -predict ed absolute 2012 base case concentration of the same species. The PSAT
- derived ratios were then multiplied by the corresponding species component concentrations comprising the 2012 base case PM2.5 design value. For calculating annual contributions, we in cluded the PSAT data for each day of the modeled year. For 24
- hour calculations, the contributions are based on the 10 percent highest of the days in each quarter, as predicted for each receptor in the 2012 base case. In the 24
-192

hour calculations, only the upwind contribution to the highest quarter at each receptor was used (i.e., highest quarter based on 2012 PM2.5 mass). For both annual and 24
- hour PM2.5 , the total PM2.5 mass contribution was calculated by summing the contributions of sulfate, nitrate, ammonium, and particle bound water 48 . Details on the procedures for calculating the contribution metrics are provided in the AQMTSD. b. 8
- Hour Ozone Contribution Modeling Approach EPA used the CAMx Ozone Source Apportionment Technique (OSAT) in order to calculate downwind 8
- hour ozone contributions to nonattainment and maintenance. OSAT tracks the formation of ozone from NO X and VOC emissions. Through emissions pre
processing procedures, EPA tagged all of the NO X and VOC emissions in each upwind state. A separate tag was created for each state, and the tagged emissions followed state boundaries (not grid cells). All anthropogenic sources of NO X and VOC were tracked in the OSAT simulation. Upwind NO X and VOC emissions were tracked to

48 The water and ammonium contributions are calculated by MATS using the default assumpt ions that were used to calculate future year 2012 PM2.5 concentrations. The ammonium contribution is calculated assuming that all particulate nitrate is in the form of ammonium nitrate and the ammonium associated with sulfate is based on the degree of neu tralization of the base year ambient data. In this way, the ammonium contribution is attributed to sulfate and nitrate precursors, not ammonia emissions. The water concentration is calculated based on an empirical formula that uses sulfate, nitrate, and ammonium concentrations.193

downwind ozone con centrations. There are several post
processing steps needed to transform the raw model outputs to ozone downwind contributions. We developed and applied several post -processing steps to transform the OSAT modeling outputs to ozone contributions at downwi nd receptors. The approach for ozone was similar to the approach for PM2.5 in that the OSAT model outputs were processed using MATS along with other post
processing software to calculate the contribution of each upwind state to each downwind nonattainment and/or maintenance receptor. This process involved calculating a ratio which uses the OSAT
-predicted absolute contribution of ozone coupled with the CAMx
-predicted absolute 2012 base case ozone concentration. The OSAT
- derived ratios were then multiplied by the corresponding 2012 base case ozone design value. The contributions to each downwind receptor are averaged across all days with modeled 2012 base case concentrations greater than 85 ppb 49 (at the given receptor). Details on the procedures for calcu lating the contribution metrics are provided in the AQMTSD. c. Use of Projected Nonattainment and Maintenance Contributions

49 Ozone contributions are averaged over a minimum of 5 days. If there are fewer than 5 days greater than 85 ppb at a receptor, then the 85 ppb criterion is lowered in 1 ppb increments until there are 5 days of data for use in th e calculations. If there are fewer than 5 modeled days greater than 70 ppb at the receptor, then the receptor is not used in the contribution calculations.194

The previous steps provide the details for calculating 8
- hour ozone and annual and 24
- hour PM2.5 contributions to all downwind recep tors. After the post
-processing of the model results is complete, we then evaluate the contributions of each upwind state to nonattainment and maintenance receptors. The nonattainment receptors are those monitoring sites, which are projected to exceed the NAAQS in the 2012 base case, based on 5
- year weighted average design values. The maintenance receptors are those monitoring sites which are projected to exceed the NAAQS in the 2012 base case based on the highest design value period. The upwind ozone a nd PM2.5 contributions from each state are calculated for each downwind receptor. Contributions to nonattainment and maintenance receptors are evaluated independently for each state to determine if they are above the 1 percent threshold criteria. For each upwind state, the maximum contribution to nonattainment is calculated based on the single largest contribution to a future year (2012) downwind nonattainment receptor. The maximum contribution to maintenance is calculated based on the single largest con tribution to a future year (2012) downwind maintenance receptor. Since the contributions are calculated independently for each receptor, the upwind contribution to maintenance can sometimes be larger than the contribution to nonattainment, and vice versa. This also means195

that maximum contributions to nonattainment can be below the threshold while maximum contributions to maintenance may be at or above the threshold, or vice versa. 4. What a re the e stimated i nterstate c ontributions to annual PM2.5 , 24
- Hour PM2.5 , and 8
- Hour o zone n onattainment and
maintenance? a. Contributions to Annual and 24
- Hour PM2.5 Nonattainment and Maintenance In this section, we present the interstate contributions from emissions in upwind states to downwind nonattainment and maint enance sites for the annual PM2.5 NAAQS. We also present the interstate contributions from emissions in upwind states to downwind nonattainment and maintenance sites for the 24
- hour PM2.5 NAAQS. As described previously in section IV.B., states which cont ribute 0.15 μg/m3 or more to annual PM2.5 nonattainment or maintenance in another state are identified as states with contributions to downwind attainment and maintenance sites large enough to warrant further analysis. For 24
- hour PM2.5 , states which cont ribute 0.35 μg/m3 or more to 24
- hour PM2.5 nonattainment or maintenance in another state are identified as states with contributions to downwind attainment and maintenance sites large enough to warrant further analysis. As described previously in section I V.C.3, we performed air quality modeling to quantify the contributions to annual and 24
- hour PM2.5 from emissions in196

each of the following 37 states individually: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas , Kentucky, Louisiana, Maine, Maryland combined with the District of Columbia, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Hampshire, New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma, Pennsylvania, Rhode Islan d, South Carolina, South Dakota, Tennessee, Texas, Vermont, Virginia, West Virginia, and Wisconsin. For annual PM2.5 , we calculated each state’s contribution to each of the 32 monitoring sites that are projected to be nonattainment and each of the 16 site s that are projected to have maintenance problems for the annual PM2.5 NAAQS in the 2012 base case. The maximum contribution from each state to annual PM2.5 nonattainment in downwind sites is provided in Table I V.C 13. The maximum contribution from each state to annual PM2.5 maintenance in downwind sites is also provided in Table I V.C - 13. The contributions from each state to all projected 2012 nonattainment and maintenance sites for the annual PM2.5 NAAQS are provided in the AQMTSD.197

Table IV.C - 13. Maximum contribution to downwind annual PM2.5 (μg/m3 ) nonattainment and maintenance for each of 37 States.

Upwind State Maximum Downwind Contribution to Nonattainment for Annual PM2.5 (ug/m3 ) Maximum Downwind Contribution to Maintenance for Annual PM2.5 (ug/m3 ) Alabama 0.46 0.18 Arkansas 0.09 0.04 Connecticut 0.04 0.09 Delaware 0.20 0.14 Florida 0.29 0.07 Georgia 0.63 0.18 Illinois 1.01 0.63 Indiana 2.09 1.78 Iowa 0.31 0.30 Kansas 0.09 0.05 Kentucky 1.68 1.01 Louisiana 0.11 0.34 Maine 0.01 0.02 Maryland 0.62 0.55 Massachusetts 0.07 0.13 Michigan 0.72 0.71 Minnesota 0.19 0.17 Mississippi 0.07 0.03 Missouri 1.38 0.27 Nebraska 0.08 0.06 New Hampshire 0.01 0.02 New Jersey 0.34 0.68 New York 0.49 0.47 North Carolin a 0.19 0.11 North Dakota 0.05 0.05 Ohio 1.49 2.03 Oklahoma 0.08 0.05 Pennsylvania 0.83 1.60 Rhode Island 0.01 0.01 South Carolina 0.26 0.04 South Dakota 0.02 0.02198 Upwind State Maximum Downwind Contribution to Nonattainment for Annual PM2.5 (ug/m3 ) Maximum Downwind Contribution to Maintenance for Annual PM2.5 (ug/m3 ) Tennessee 0.68 0.64 Texas 0.13 0.06 Vermont 0.00 0.00 Virginia 0.36 0. 37 West Virginia 0.98 1.17 Wisconsin 0.46 0.42
Based on the state
-by
- state contribution analysis, there are 22 states and the District of Columbia 50 which contribute 0.15 μg/m3 or more to downwind annual PM2.5 nonattainment. These states are : Alabama, the District of Columbia, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Maryland, Michigan, Minnesota, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and Wisconsi n. In Table I V.C - 14, we provide a list of the downwind nonattainment sites to which each upwind State contributes 0.15 μg/m3 or more (i.e., the upwind State - to - downwind nonattainment “linkages”).

50 EPA combined Maryland and the District of Columbia as a single entity in our contribution model ing. This is a logical approach because of the small size of the District of Columbia and, hence, its emissions and its close proximity to Maryland.199

There are 19 states and the District of Columbia 51 which
c ontribute 0.15 μg/m3 or more to downwind annual PM2.5 maintenance. These states are : Alabama, the District of Columbia, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Missouri, New Jersey, New York, Ohio, Pennsylvan ia, Tennessee, Virginia, West Virginia, and Wisconsin. In Table I V.C - 15, we provide a list of the downwind maintenance sites to which each upwind State contributes 0.15 μg/m3 or more (i.e., the upwind State
- to - downwind maintenance “linkages”).

51 As noted above, we combined Maryland and the District of Columbia as a single entity in our contributio n modeling. This is a logical approach because of the small size of the District of Columbia and, hence, its emissions and its close proximity to Maryland.200

Table IV .C - 14. Upwind S tate - to -Downwind Nonattainment S ite “ Linkages” for Annual PM2.5 . Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Nonattainment Sites (Monitoring Site ID)
Alabama 6 Bibb, GA (130210007) Clayton, GA

(130630091) Ful ton, GA

(131210039) Clark, IN

(180190006) Dubois, IN

(180372001) Jefferson,

KY (211110043)
Delaware 2 Lancaster, PA (420710007) York, PA

(421330008)
Florida 3 Jefferson, AL (10730023) Bibb, GA

(130210007) Clayton, GA

(130630091) Georgi a 7 Jefferson, AL (10730023) Jefferson,

AL (10732003) Clark, IN

(180190006) Dubois, IN

(180372001) Jefferson,

KY (211110043) Kanawha, WV

(540391005) Cabell, WV

(540110006)
Illinois 29 Jefferson, AL (10730023) Jefferson,

AL (10732003) Fulton, GA

(131210039 ) Bibb, GA

(130210007) Clayton, GA

(130630091) Clark, IN

(180190006) Dubois, IN

(180372001) Marion, IN (180970078) Marion, IN

(180970081) Marion, IN

(180970083) Jefferson,

KY (211110043) Wayne, MI

(261630015) Wayne, MI

(261630033) Butler, OH

(39017001 6) Cuyahoga, OH (390350038) Cuyahoga,

OH (390350045) Cuyahoga,

OH (390350060) Hamilton,

OH (390610014) Hamilton,

OH (390610042) Hamilton,

OH (390610043) Hamilton,

OH (390617001) Hamilton, OH (390618001) Allegheny,

PA (420030064) Allegheny,

PA (42 0031301) Beaver, PA

(420070014) Lancaster,

PA (420710007) York, PA

(421330008) Cabell, WV

(540110006) Kanawha, WV (540391005)
Indiana 27 Jefferson, AL (10730023) Jefferson,

AL (10732003) Bibb, GA

(130210007) Clayton, GA

(130630091) Fulton , GA

(131210039) Cook, IL

(170310052) Madison, IL

(171191007) Saint Clair, IL Jefferson,

KY Wayne, MI

(261630015) Wayne, MI

(261630033) Butler, OH

(390170016) Cuyahoga,

OH Cuyahoga,

OH201

Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Nonattainment Sites (Monitoring Site ID)

(171630010) (211110043) (390350038) (390350045) Cuyahoga, OH (390350060) Hamilton,

OH (390618001) Hamilton,

OH (390610014) Hamilton,

OH (390610042) Hamilton,

OH (390610043) Hamilton,

OH (390617001) Allegheny,

PA (420030064) Allegheny, PA (420031301) Beaver, PA

(420070014) Lancaster,

PA (420710007) York, PA

(421 330008) Cabell, WV

(540110006) Kanawha, WV

(540391005)

Iowa 4 Cook, IL (170310052) Madison, IL

(171191007) Saint

Clair, IL (171630010) Dubois, IN

(180372001) Kentucky 31 Jefferson, AL (10730023) Jefferson,

AL (10732003) Bibb, GA

(130210007) Clayt on, GA

(130630091) Fulton, GA

(131210039) Cook, IL

(170310052) Madison, IL

(171191007) Saint Clair, IL (171630010) Clark, IN

(180190006) Dubois, IN

(180372001) Marion, IN

(180970078) Marion, IN

(180970081) Marion, IN

(180970083) Wayne, MI

(261630015) Wayne, MI (261630033) Butler, OH

(390170016) Cuyahoga,

OH (390350038) Cuyahoga,

OH (390350045) Cuyahoga,

OH (390350060) Hamilton,

OH (390610014) Hamilton,

OH (390610042) Hamilton, OH (390610043) Hamilton,

OH (390617001) Hamilton,

OH (390618001) Allegheny,

PA (420030064) Allegheny,

PA (420031301) Beaver, PA

(420070014) Lancaster,

PA (420710007) York, PA (421330008) Cabell, WV

(540110006) Kanawha, WV

(540391005) Maryland 2 Lancaster, PA (420710007) York, PA

(421330008)
Michi gan 25 Cook, IL (170310052) Madison, IL

(171191007) Saint

Clair, IL (171630010) Clark, IN

(180190006) Dubois, IN

(180372001) Marion, IN

(180970078) Marion, IN

(180970081) Marion, IN (180970083) Jefferson,

KY Butler, OH

(390170016) Cuyahoga ,

OH Cuyahoga,

OH Cuyahoga,

OH Hamilton,

OH2 02

Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Nonattainment Sites (Monitoring Site ID) (211110043) (390350038) (390350045) (390350060) (390610014) Hamilton, OH (390610042) Hamilton,

OH (390610043) Hamilton,

OH (390617001) Hamilton,

OH (390618001) Allegheny,

PA (420030064) Allegheny,

PA (420031301) Beaver, PA

(420070014) Lancaster, PA (420710007) York, PA

(421330008) Cabell, WV

(540110006) Kanawha, WV

(540391005) Minnesota 1 Cook, IL (170310052)
Missouri 17 Cook, IL (170310052) Madison, IL

(171191007) Saint

Clair, IL (171630010) Cla rk, IN

(180190006) Dubois, IN

(180372001) Marion, IN

(180970078) Marion, IN

(180970081) Marion, IN (180970083) Jefferson,

KY (211110043) Butler, OH

(390170016) Hamilton,

OH (390610014) Hamilton,

OH (390610042) Hamilton,

OH (390610043) Hamilton,

OH (39 0617001) Hamilton, OH (390618001) Cabell, WV

(540110006) Kanawha, WV

(540391005)
New Jersey 2 Lancaster, PA (420710007) York, PA

(421330008)
New York 8 Cuyahoga, OH (390350038) Cuyahoga,

OH (390350045) Cuyahoga,

OH (390350060) Alle gheny,

PA (420030064) Allegheny,

PA (420031301) Beaver, PA

(420070014) Lancaster,

PA (420710007) York, PA (421330008) North Carolina 3 Bibb, GA (130210007) Clayton, GA

(130630091) Fulton, GA

(131210039)
Ohio 23 Jefferson, AL (107 30023) Jefferson,

AL (10732003) Bibb, GA

(130210007) Clayton, GA

(130630091) Fulton, GA

(131210039) Cook, IL

(170310052) Madison, IL

(171191007)203

Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Nonattainment Sites (Monitoring Site ID)

Saint Clair, IL (171630010) Clark, IN

(180190006) Dubois, IN

(180372001) Marion, IN

(180970078) Marion, IN

(180970081) Marion, IN

(180970083) Jefferson,

KY (211110043) Wayne, MI (261630015) Wayne, MI

(261630033) Allegheny,

PA (420030064) Allegheny,

PA (420031301) Beaver, PA

(420070014) Lancaster,

PA (420710007) York, PA

(421330008) Cabell, WV (540110 006) Kanawha, WV

(540391005) Pennsylvania 25 Bibb, GA (130210007) Clayton, GA

(130630091) Fulton, GA

(131210039) Cook, IL

(170310052) Madison, IL

(171191007) Saint

Clair, IL (171630010) Clark, IN

(180190006) Dubois, IN (180372001) Marion, I N

(180970078) Marion, IN

(180970081) Marion, IN

(180970083) Jefferson,

KY (211110043) Wayne, MI

(261630015) Wayne, MI

(261630033) Butler, OH (390170016) Cuyahoga,

OH (390350038) Cuyahoga,

OH (390350045) Cuyahoga,

OH (390350060) Hamilton,

OH (390610014 ) Hamilton,

OH (390610042) Hamilton,

OH (390610043) Hamilton, OH (390617001) Hamilton,

OH (390618001) Cabell, WV

(540110006) Kanawha, WV

(540391005) South Carolina 3 Bibb, GA (130210007) Clayton, GA

(130630091) Fulton, GA

(131210039)

T ennessee 29 Jefferson, AL (10730023) Jefferson,

AL (10732003) Bibb, GA

(130210007) Clayton, GA

(130630091) Fulton, GA

(131210039) Clark, IN

(180190006) Madison, IL

(171191007) Saint Clair, IL (171630010) Dubois, IN

(180372001) Marion, IN

(180970078) Marion, IN

(180970081) Marion, IN

(180970083) Jefferson,

KY (211110043) Wayne, MI

(261630015) Wayne, MI (261630033) Butler, OH

(390170016) Cuyahoga,

OH (390350038) Cuyahoga,

OH (390350045) Cuyahoga,

OH (390350060) Hamilton,

OH (390610014) Hamilton,

OH (390610042) Hamilton, OH Hamilton,

OH Hamilton,

OH Allegheny,

PA Allegheny,

PA Beaver, PA

(420070014) Cabell, WV

(540110006)204

Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Nonattainment Sites (Monitoring Site ID)

(390610043) (390617001) (390618001) (420030064) (420031301) Kanawha, WV (540391005) Virginia 4 Lancaster, PA (420710007) York, PA

(421330008) Cabell, WV

(540110006) Kanawha, WV

(540391005) West Virginia 25 Fulton, GA (131210039) Bibb, GA

(130210007) Clayton, GA

(130630091) Clark, IN

(180190006) Marion, IN

(180970078) Marion, IN

(180970081) Marion, IN

(180 970083) Dubois, IN (180372001) Jefferson,

KY (211110043) Wayne, MI

(261630015) Wayne, MI

(261630033) Butler, OH

(390170016) Cuyahoga,

OH (390350038) Cuyahoga,

OH (390350045) Cuyahoga, OH (390350060) Hamilton,

OH (390610014) Hamilton,

OH (39061004 2) Hamilton,

OH (390610043) Hamilton,

OH (390617001) Hamilton,

OH (390618001) Allegheny,

PA (420030064) Allegheny, PA (420031301) Beaver, PA

(420070014) Lancaster,

PA (420710007) York, PA

(421330008) Wisconsin 8 Cook, IL (170310052) Dubois, IN

(180372001) Marion, IN

(180970078) Marion, IN

(180970081) Marion, IN

(180970083) Wayne, MI

(261630015) Wayne, MI

(261630033) Cuyahoga, OH (390350045)205

Table IV.C - 15. Upwind S tate - to -Downwind Maintenance S ite “ Linkages” for Annual PM2. 5 .
Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Maintenance Sites (Monitoring Site ID) Alabama 1 Jefferson, KY (211110044) Georgia 1 Jefferson, KY (211110044)

Illinois 13 Jefferson, KY (211110044) Cu yahoga,

OH (390350027) Cuyahoga,

OH (390350065 ) Hamilton, OH

(390610040) Jefferson,

OH (390811001) Montgomery,

OH (391130032) Stark, OH

(391510017) Berks, PA (420110011) Harris, TX

(482011035) Berkeley,

WV (540030003 ) Brooke, WV

(540090005) Hancock, WV

(540291004) Marion, WV

(540490006)

Indiana 16 Cook, IL (170313301) Cook, IL

(170316005) Jefferson,

KY (211110044 ) New York, NY

(360610056) Cuyahoga,

OH (390350027) Cuyahoga, OH

(390350065) Hamilton, OH

(390610040) Jefferson, OH (390811001) Montgomery,

OH (391130032) Stark, OH

(391510017 ) Berks, PA

(420110011) Harris, TX

(482011035) Berkeley, WV

(540030003) Brooke, WV

(540090005) Hancock, WV (540291004) Marion, WV

(540490006) Iowa 2 Cook, IL (170313301) Cook, IL

(170316005)
Kentucky 12 Cook, IL (170313301) Cook, IL

(170316005) Cuyahoga,

OH (390350027 ) Cuyahoga, OH

(390350065) Hamilton,

OH (390610040) Jefferson,

OH (390811001) Montgomery,

OH (391130032) Stark, OH (391510017) Berkeley,

WV Brooke, WV

(540090005 Hancock, WV

(540291004) Marion, WV

(540490006)206

Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Maintenance Sites (Monitoring Site ID) (540030003) )

Louisiana 1 Harris, TX (482011035) Maryland 2 Berks, PA (420110011) Berkeley,

WV (540030003)
Michigan 15 Cook, IL (170313301) Cook, IL

(170316005) Jefferson,

KY (211110044 ) New York, NY

(360610056) Cuyahoga,

OH (390350027) Cuyahoga, OH

(390350065) Hamilton, OH

(390610040) Jefferson, OH (390811001) Montgomery,

OH (391130032) Stark, OH

(391510017 ) Berks, PA

(420110011) Berkeley,

WV (540030003) Brooke, WV

(540090005) Hancock, WV

(540291004) Marion, WV (540490006) Minnesota 1 Cook, IL (170316005)

Missouri 6 Cook, IL (170313301) Cook, IL

(170316005) Jefferson,

KY (211110044 ) Hamilton, OH

(390610040) Montgomery,

OH (391130032) Stark, OH

(391510017) New Jer sey 2 New York, NY (360610056) Berks, PA

(420110011)

New York 9 Cuyahoga, OH (390350027) Cuyahoga,

OH (390350065) Jefferson,

OH (390811001 ) Stark, OH

(391510017) Berks, PA

(420110011) Berkeley, WV

(540030003) Brooke, WV

(540090005) Hancoc k, WV (540291004) Marion, WV

(540490006) Ohio 9 Cook, IL (170313301) Cook, IL

(170316005) Jefferson,

KY New York, NY

(360610056) Berks, PA

(420110011) Berkeley, WV

(540030003) Brooke, WV

(540090005)207

Upwind State Number

of Linkages Counties Containing Downwind Annual PM2.5 Maintenance Sites (Monitoring Site ID) (211110044 ) Hancock, WV (540291004) Mar ion, WV

(540490006) Pennsylvan ia 14 Cook, IL (170313301) Cook, IL

(170316005) Jefferson,

KY (211110044 ) New York, NY

(360610056) Cuyahoga,

OH (390350027) Cuyahoga, OH

(390350065) Hamilton, OH

(390610040) Jefferson, OH (390811001) Montgomery ,

OH (391130032) Stark, OH

(391510017 ) Berkeley, WV

(540030003) Brooke, WV

(540090005) Hancock, WV

(540291004) Marion, WV

(540490006)

Tennessee 10 Jefferson, KY (211110044) Cuyahoga,

OH (390350027) Cuyahoga,

OH (390350065 ) Hamilton, OH

(390610040) Jeffers on,

OH (390811001) Montgomery,

OH (391130032) Stark, OH

(391510017) Brooke, WV (540090005) Hancock, WV

(540291004) Marion, WV

(540490006 )
Virginia 4 New York, NY (360610056) Berks, PA

(420110011) Berkeley,

WV (540030003 ) Marion, WV

(540490006 )

West Virginia 9 Jefferson, KY (211110044) New York,

NY (360610056) Cuyahoga,

OH (390350027 ) Cuyahoga, OH

(390350065) Hamilton,

OH (390610040) Jefferson,

OH (390811001) Montgomery,

OH (391130032) Stark, OH (391510017) Berks, PA

(420110011) Wisconsin 2 Cook, IL (170313301) Cook, IL

(170316005)208 For 24
- hour PM2.5 , we calculated each state’s contribution to each of the 92 monitoring sites that are projected to be nonattainment and each of the 38 sites that are projected to have maintenance problems for the 24
- hour PM2.5 NAAQS in the 2012 base case. The maximum contribution from each state to 24
- hour PM2.5 nonattainment in downwind sites is provided in Table I V.C - 16. The maximum contribution from each state to 24
- hour PM2.5 maintenance in downwind sites is also provided in Table I V.C - 16. The contributions from each state to all projected 2012 nonattainment and maintenance sites for the 24
- hour PM2.5 NAAQS are provided in the AQMTSD. Table IV.C - 16. Maximum Contribution to Downwind 24 -Hour PM2.5 (μg/m3 ) Nonattainment and Maintenance for each of 37 States.

Upwind State Maximum Downwind

Contribution to Nonattainment for 24
- Hour PM2.5 (ug/m3 ) Maximum Downwind Contribution to Maintenance for 24
- Hour PM2.5 (ug/m3 ) Alabama 0.48 0.32 Arkansas 0.20 0.17 Connecticut 0.41 0.70 Delaware 0.50 0.36 Florida 0.08 0.08 Georgia 0.95 0.41 Illinois 7.28 6.57 Indiana 9.91 8.94 Iowa 1.87 1.67 Kansas 0.77 0.45 Kentucky 6.53 6.91 Louisiana 0.23 0.18 Maine 0.19 0.19209

Upwind State Maximum Downwind

Contribution to Nonattainment for 24
- Hour PM2.5 (ug/m3 ) Maximum Downwind Contribution to Maintenance for 24
- Hour PM2.5 (ug/m3 ) Mary land 2.52 2.84 Massachusetts 0.67 0.71 Michigan 2.35 3.35 Minnesota 0.91 0.86 Mississippi 0.09 0.04 Missouri 5.03 4.82 Nebraska 0.62 0.39 New Hampshire 0.21 0.23 New Jersey 2.69 4.74 New York 5.82 1.17 North Carolina 0.50 0.45 North Dakota 0.27 0.15 Ohio 5.84 5.56 Oklahoma 0.16 0.21 Pennsylvania 3.67 4.86 Rhode Island 0.05 0.06 South Carolina 0.19 0.19 South Dakota 0.13 0.09 Tennessee 3.92 4.70 Texas 0.21 0.28 Vermont 0.06 0.07 Virginia 1.32 2.26 West Virginia 3.5 1 4.83 Wisconsin 0.80 1.01
Based on the state
-by
- state contribution analysis, there are 24 States and the District of Columbia 52 which contribute 0.35 μg/m3 or more to downwind 24
- hour PM2.5

52 As noted above, we combined Maryland and the District of Columbia as a single entity in our cont ribution modeling. This is a logical approach because of the small size of the District of Columbia and, hence, its emissions and its close proximity to Maryland.210

nonattainment. These states are : Alabama, the District of Columbia, Connecticut, Delaware, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wiscons in. In Table I V.C - 17, we provide a list of the downwind nonattainment counties to which each upwind State contributes 0.35 μg/m3 or more (i.e., the upwind State
- to - downwind nonattainment “linkages”). There are 23 states and the District of Columbia which contribute 0.35 μg/m3 or more to downwind 24
- hour PM2.5 maintenance. These states are : Connecticut, Delaware, the District of Columbia, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Nebraska , New Jersey, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. In Table I V.C - 18, we provide a list of the downwind maintenance sites to which each upwind State contributes 0.35 μg/m3 or more (i.e., the upwin d State - to - downwind maintenance “linkages”).211

Table IV.C - 17. Upwind S tate - to -Downwind Nonattainment S ite “ Linkages” for 24 -Hour PM2.5 . Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID) Alabama 5 Monroe, MI (261150005) Wayne, MI

(261630015) Hamilton, OH

(390610006) Hamilton, OH

(390610014) Hamilton, OH

(390618001) Connecticut 3 Hudson, NJ (340172002) New York, NY

(360610056) New York, NY

(360610128) Delaware 2 Union, NJ (34039 0004) Dauphin, PA

(420430401) Georgia 12 Jefferson, AL (10730023) Jefferson, AL

(10732003) Baltimore

City, MD (245100040) Baltimore

City, MD (245100049) Union, NJ

(340390004) Butler, OH

(390170016) Butler, OH (390171004) Hamilton, OH

(3906100 06) Hamilton, OH

(390610014) Hamilton, OH

(390618001) Montgomery,

OH (391130032) York, PA

(421330008) Illinois 70 Jefferson, AL (10730023) Jefferson, AL

(10732003) New Haven, CT

(90091123) Clark, IN

(180190006) Dubois, IN

(180372001) Knox, IN

(180830004) Lake, IN (180890022) Lake, IN

(180890026) Marion, IN

(180970042) Marion, IN

(180970043) Marion, IN

(180970066) Marion, IN

(180970078) Marion, IN (180970079) Marion, IN

(180970081) Marion, IN

(180970083) Tippecanoe, IN

(181570008) Scott, IA

(19163 0019) Daviess, KY

(210590005) Jefferson, KY (211110043) Jefferson, KY

(211110044) Jefferson, KY

(211110048) Monroe, MI

(261150005) Oakland, MI

(261250001) St. Clair, MI

(261470005) Washtenaw, MI (261610008) Wayne, MI

(261630015) Wayne, MI

(261630 016) Wayne, MI

(261630019) Wayne, MI

(261630033) Wayne, MI

(261630036) Jefferson, MO (290990012) Saint

Charles, MO (291831002) St. Louis

City, MO (295100007) St. Louis

City, MO (295100087) Union, NJ

(340390004) New York, NY

(360610128) Butler, OH (390170003) Butler, OH

(390170016) Butler, OH

(390170017) Butler, OH

(390171004) Cuyahoga, OH

(390350038) Cuyahoga, OH

(390350045)212

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

Cuyahoga, OH (390350060) Cuyahoga, OH

(390350065) Franklin, OH

(390490024) Franklin, OH

(390490025) Hamilton, OH

(39061 0006) Hamilton, OH

(390610014) Hamilton, OH (390610040) Hamilton, OH

(390610042) Hamilton, OH

(390610043) Hamilton, OH

(390617001) Hamilton, OH

(390618001) Jefferson, OH

(390811001) Montgomery, OH (391130032) Summit, OH

(391530017) Allegheny, PA

(420030064) Allegheny, PA

(420030093) Allegheny, PA

(420030116) Allegheny, PA

(420031008) Allegheny, PA (420031301) Beaver, PA

(420070014) Berks, PA

(420110011) Cambria, PA

(420210011) Montgomery,

TN (471251009) Brooke, WV

(540090011) Milwaukee, WI (550790010) Milwaukee, WI

(550790026) Milwaukee, WI

(550790043) Milwaukee, WI

(550790099) Indiana 75 Jefferson, AL (10730023) Jefferson, AL

(10732003) New Haven, CT

(90091123) Cook, IL

(170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL (170311016) Cook, IL

(170312001) Cook, IL

(170313103) Cook, IL

(170313301) Cook, IL

(170316005) Madison, IL

(171190023) Madison, IL (171191007) Madison, IL

(171192009) Madison, IL

(171193007) Scott, IA

(191630019) Daviess, KY

(210590005) Jefferson, KY

(211110043) Jefferson, KY (211110044) Jefferson, KY

(211110048) Monroe, MI

(261150005) Oakland, MI

(261250001) St. Clair, MI

(261470005) Washtenaw, MI

(261610008) Wayne, MI (261630015) Wayne, MI

(261630016) Wayne, MI

(261630019) Wayne, MI

(2616 30033) Wayne, MI

(261630036) Jefferson, MO

(290990012) Saint Charles, MO (291831002) St. Louis

City, MO (295100007) St. Louis

City, MO (295100087) Hudson, NJ

(340171003) Union, NJ

(340390004) Bronx, NY

(360050080) New York, NY (360610056) New Yor k, NY

(360610128) Butler, OH

(390170003) Butler, OH

(390170016) Butler, OH

(390170017) Butler, OH

(390171004) Cuyahoga, OH (390350038) Cuyahoga, OH

(390350045) Cuyahoga, OH

(390350060) Cuyahoga, OH

(390350065) Franklin, OH

(390490024) Franklin, OH

(39 0490025) Hamilton, OH (390610006) Hamilton, OH

(390610014) Hamilton, OH

(390610040) Hamilton, OH

(390610042) Hamilton, OH

(390610043) Hamilton, OH

(390617001)213

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

Hamilton, OH (390618001) Jefferson, OH

(390811001) Montgomery, OH

(391130032) Summit, OH

(391530017) Allegheny, PA

(420030008) Allegheny, PA

(420030064) Allegheny, PA (420030093) Allegheny, PA

(420030116) Allegheny, PA

(420031008) Allegheny, PA

(420031301) Beaver, PA

(420070014) Berks, PA

(420110011) Cambria, PA (420210011) Dauphin , PA

(420430401) York, PA

(421330008) Montgomery, TN

(471251009) Brooke, WV

(540090011) Milwaukee, WI

(550790010) Milwaukee, WI (550790026) Milwaukee, WI

(550790043) Milwaukee, WI

(550790099) Iowa 17 Cook, IL (170310052) Cook, IL

(170310057) Coo k, IL

(170310076) Cook, IL

(170311016) Cook, IL

(170312001) Cook, IL

(170313103) Cook, IL (170313301) Cook, IL

(170316005) Madison, IL

(171191007) Lake, IN

(180890022) Lake, IN

(180890026) Jefferson, MO

(290990012) St. Louis City, MO (295100007) Milwaukee, WI

(550790010) Milwaukee, WI

(550790026) Milwaukee, WI

(550790043) Milwaukee, WI

(550790099) Kansas 3 Milwaukee, WI (550790010) Milwaukee, WI

(550790026) Milwaukee, WI

(550790099) Kentucky 81 Jefferson, AL (10730023) Jefferson, AL

(107 32003) New Haven, CT

(90091123) Cook, IL

(170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL (170311016) Cook, IL

(170312001) Cook, IL

(170313103) Cook, IL

(170313301) Cook, IL

(170316005) Madison, IL

(171190023) Madison, IL (171191007 ) Madison, IL

(171192009) Madison, IL

(171193007) Clark, IN

(180190006) Dubois, IN

(180372001) Knox, IN

(180830004) Lake, IN (180890026) Marion, IN

(180970042) Marion, IN

(180970043) Marion, IN

(180970066) Marion, IN

(180970078) Marion, IN

(180970079) Marion, IN (180970081) Marion, IN

(180970083) Tippecanoe, IN

(181570008) Scott, IA

(191630019) Monroe, MI

(261150005) Oakland, MI

(261250001) St. Clair, MI (261470005) Washtenaw, MI

(261610008) Wayne, MI

(261630015) Wayne, MI

(261630016) Wayne, MI

(261630019) Wayne, MI

(261630033) Wayne, MI (261630036) Jefferson, MO

(290990012) Saint Charles,

MO (291831002) St. Louis

City, MO St. Louis

City, MO Hudson, NJ

(340171003)214

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID) (295100007) (295100087) Union, NJ (340390004) Bronx, NY

(360050080) New York, NY

(360610128) Butler, OH

(390170003) Butler, OH

(390170016) Butler, OH

(390170017) Butler, OH (390171004) Cuyahoga, OH

(390350038) Cuyahoga, OH

(390350045) Cuyahoga, OH

(390350060) Cuyahoga, OH

(390350065) Franklin, OH

(390490024) Frankl in, OH (390490025) Hamilton, OH

(390610006) Hamilton, OH

(390610014) Hamilton, OH

(390610040) Hamilton, OH

(390610042) Hamilton, OH

(390610043) Hamilton, OH (390617001) Hamilton, OH

(390618001) Jefferson, OH

(390811001) Montgomery, OH

(391130032) Summit, OH

(391530017) Allegheny, PA

(420030008) Allegheny, PA (420030064) Allegheny, PA

(420030093) Allegheny, PA

(420030116) Allegheny, PA

(420031008) Allegheny, PA

(420031301) Beaver, PA

(420070014) Berks, PA (420110011) Cambria, PA

(420210011) Yo rk, PA

(421330008) Montgomery, TN

(471251009) Brooke, WV

(540090011) Milwaukee, WI

(550790010) Milwaukee, WI (550790026) Milwaukee, WI

(550790043) Milwaukee, WI

(550790099) Maryland 11 New Haven, CT (90091123) Hudson, NJ

(340171003) Hudson, NJ

( 340172002) Union, NJ

(340390004) Bronx, NY

(360050080) New York, NY

(360610056) New York, NY (360610128) Berks, PA

(420110011) Dauphin, PA

(420430401) Lancaster, PA

(420710007) York, PA

(421330008) Massachusetts 3 New Haven, CT (90091123) New York, NY

(360610056) New York, NY

(360610128) Michigan 48 Cook, IL (170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL

(170311016) Cook, IL

(170312001) Cook, IL

(170313103) Cook, IL (170313301) Cook, IL

(170316005) Madison, IL

(171190023) Madison, IL

(171191007) Madison, IL

(171192009) Madison, IL

(171193007) Knox, IN (180830004) Lake, IN

(180890022) Lake, IN

(180890026) Scott, IA

(191630019) Jefferson, MO

(290990012) Saint

Charles, MO (291831002) St. Louis City, MO S t. Louis

City, MO New York, NY

(360610128) Cuyahoga, OH

(390350038) Cuyahoga, OH

(390350045) Cuyahoga, OH

(390350060)215

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

(295100007) (295100087) Cuyahoga, OH (390350065) Franklin, OH

(390490024) Franklin, OH

(390490025) Hamilton, OH

(390610014) Hamilton, OH

(3906170 01) Hamilton, OH

(390618001) Jefferson, OH (390811001) Montgomery,

OH (391130032) Summit, OH

(391530017) Allegheny, PA

(420030008) Allegheny, PA

(420030064) Allegheny, PA

(420030093) Allegheny, PA (420030116) Allegheny, PA

(420031008) Allegheny, PA

(420031301) Beaver, PA

(420070014) Cambria, PA

(420210011) Dauphin, PA

(420430401) Montgomery, TN (471251009) Brooke, WV

(540090011) Milwaukee, WI

(550790010) Milwaukee, WI

(550790026) Milwaukee, WI

(550790043) Milwaukee, WI (550790099) Minnesota 4 Milwaukee, WI (550790010) Milwaukee, WI

(550790026) Milwaukee, WI

(550790043) Milwaukee, WI

(550790099) Missouri 56 Cook, IL (170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL

(170311016) Cook, IL

(170312001) Cook, IL

(170313 103) Cook, IL (170313301) Cook, IL

(170316005) Madison, IL

(171190023) Madison, IL

(171191007) Madison, IL

(171192009) Madison, IL

(171193007) Clark, IN (180190006) Dubois, IN

(180372001) Knox, IN

(180830004) Lake, IN

(180890022) Lake, IN

(180890 026) Marion, IN

(180970042) Marion, IN (180970043) Marion, IN

(180970066) Marion, IN

(180970078) Marion, IN

(180970079) Marion, IN

(180970081) Marion, IN

(180970083) Tippecanoe, IN (181570008) Scott, IA

(191630019) Daviess, KY

(210590005) Jeffers on, KY

(211110043) Jefferson, KY

(211110044) Jefferson, KY

(211110048) Monroe, MI (261150005) Oakland, MI

(261250001) Washtenaw, MI

(261610008) Wayne, MI

(261630015) Wayne, MI

(261630033) Wayne, MI

(261630036) Butler, OH (390170003) Butler, OH

(3 90170016) Butler, OH

(390170017) Butler, OH

(390171004) Franklin, OH

(390490024) Franklin, OH

(390490025)216

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

Hamilton, OH (390610006) Hamilton, OH

(390610014) Hamilton, OH

(390610040) Hamilton, OH

(390610042) Hamilton, OH

(390610043) Hamilton, OH

(390617 001) Hamilton, OH (390618001) Montgomery,

OH (391130032) Allegheny, PA

(420030116) Montgomery, TN

(471251009) Milwaukee, WI

(550790010) Milwaukee, WI

(550790026) Milwaukee, WI (550790043) Milwaukee, WI

(550790099) Nebraska 3 Milwaukee, WI (5 50790010) Milwaukee, WI

(550790026) Milwaukee, WI

(550790099)
New Jersey 9 New Haven, CT (90091123) Baltimore

City, MD (245100049) Bronx, NY

(360050080) New York, NY

(360610056) New York, NY

(360610128) Berks, PA

(420110011) Dauphin, PA (420430 401) Lancaster, PA

(420710007) York, PA

(421330008)
New York 23 New Haven, CT (90091123) Baltimore

City, MD (245100040) Baltimore

City, MD (245100049) St. Clair, MI

(261470005) Washtenaw, MI

(261610008) Wayne, MI

(261630016) Wayne, MI (26163001 9) Wayne, MI

(261630033) Wayne, MI

(261630036) Hudson, NJ

(340171003) Hudson, NJ

(340172002) Union, NJ

(340390004) Cuyahoga, OH (390350038) Cuyahoga, OH

(390350045) Cuyahoga, OH

(390350060) Cuyahoga, OH

(390350065) Franklin, OH

(390490024) Franklin, OH

(390490025) Summit, OH (391530017) Berks, PA

(420110011) Dauphin, PA

(420430401) Lancaster, PA

(420710007) York, PA

(421330008) North Carolina 11 Baltimore City, MD (245100040) Baltimore

City, MD (245100049) Hudson, NJ

(340171003) Hudson, NJ

(3401 72002) Union, NJ

(340390004) Bronx, NY

(360050080) New York, NY (360610056) Berks, PA

(420110011) Dauphin, PA

(420430401) Lancaster, PA

(420710007) York, PA

(421330008) Ohio 72 Jefferson, AL (10730023) Jefferson, AL

(10732003) New Haven, CT

(900911 23) Cook, IL

(170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL (170311016) Cook, IL

(170312001) Cook, IL

(170313103) Cook, IL

(170313301) Cook, IL

(170316005) Madison, IL

(171190023)217

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

Madison, IL (171191007) Madison, IL

(171192009) Ma dison, IL

(171193007) Clark, IN

(180190006) Dubois, IN

(180372001) Knox, IN

(180830004) Lake, IN (180890022) Lake, IN

(180890026) Marion, IN

(180970042) Marion, IN

(180970043) Marion, IN

(180970066) Marion, IN

(180970078) Marion, IN (180970079) Marion, IN

(180970081) Marion, IN

(180970083) Tippecanoe,

IN (181570008) Scott, IA

(191630019) Daviess, KY

(210590005) Jefferson, KY (211110043) Jefferson, KY

(211110044) Jefferson, KY

(211110048) Baltimore

(City, MD (245100040) Baltimore

(City, MD (24 5100049) Monroe, MI

(261150005) Oakland, MI (261250001) St. Clair, MI

(261470005) Washtenaw, MI

(261610008) Wayne, MI

(261630015) Wayne, MI

(261630016) Wayne, MI

(261630019) Wayne, MI (261630033) Wayne, MI

(261630036) Jefferson, MO

(290990012) Sa int

Charles, MO (291831002) St. Louis

City, MO (295100007) St. Louis

City, MO (295100087) Hudson, NJ (340171003) Hudson, NJ

(340172002) Union, NJ

(340390004) Bronx, NY

(360050080) New York, NY

(360610056) New York, NY

(360610128) Allegheny, PA (4 20030008) Allegheny, PA

(420030064) Allegheny, PA

(420030093) Allegheny, PA

(420030116) Allegheny, PA

(420031008) Allegheny,

PA (420031301) Beaver, PA (420070014) Berks, PA

(420110011) Cambria, PA

(420210011) Dauphin, PA

(420430401) Lancaster, PA

(420 710007) York, PA

(421330008) Montgomery, TN (471251009) Brooke, WV

(540090011) Milwaukee, WI

(550790010) Milwaukee, WI

(550790026) Milwaukee, WI

(550790043) Milwaukee,

WI (550790099) Pennsylvania 77 Jefferson, AL (10730023) Jefferson, AL

(10732003) New Haven, CT

(90091123) Cook, IL

(170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL (170311016) Cook, IL

(170312001) Cook, IL

(170313103) Cook, IL

(170313301) Cook, IL

(170316005) Madison, IL

(171191007) Madison, IL (171192009) Madiso n, IL

(171193007) Madison, IL

(171190023) Clark, IN

(180190006) Dubois, IN

(180372001) Knox, IN

(180830004) Lake, IN (180890026) Marion, IN

(180970042) Marion, IN

(180970043) Marion, IN

(180970066) Marion, IN

(180970078) Marion, IN

(180970079)218

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

Ma rion, IN (180970081) Marion, IN

(180970083) Tippecanoe, IN

(181570008) Scott, IA

(191630019) Jefferson, KY

(211110043) Jefferson,

KY (211110044) Jefferson, KY (211110048) Baltimore

City, MD (245100040) Baltimore

City, MD (245100049) Monroe, MI

(261150 005) Oakland, MI

(261250001) St. Clair,

MI (261470005) Washtenaw, MI (261610008) Wayne, MI

(261630015) Wayne, MI

(261630016) Wayne, MI

(261630019) Wayne, MI

(261630033) Wayne, MI

(261630036) Jefferson, MO (290990012) Saint

Charles, MO (291831002) St. Louis

City, MO (295100007) St. Louis

City, MO (295100087) Hudson, NJ

(340171003) Hudson, NJ

(340172002) Union, NJ (340390004) Bronx, NY

(360050080) New York, NY

(360610056) New York, NY

(360610128) Butler, OH

(390170003) Butler, OH

(390170016) Butler, OH (390170017) Butler, OH

(390171004) Cuyahoga, OH

(390350038) Cuyahoga, OH

(390350045) Cuyahoga, OH

(390350060) Cuyahoga, OH

(390350065) Franklin, OH (390490024) Franklin, OH

(390490025) Hamilton, OH

(390610006) Hamilton, OH

(390610014) Hamilton, OH

(390610040) Hamilton, OH

(390610042) Hamilton, OH (390610043) Hamilton, OH

(390617001) Hamilton, OH

(390618001) Jefferson, OH

(390811001) Montgomery,

OH (391130032) Summit, OH

(391530017) Montgomery, TN (471251009) Brooke, WV

(54009001 1) Milwaukee, WI

(550790026) Milwaukee, WI

(550790043) Milwaukee, WI

(550790099) Tennessee 61 Jefferson, AL (10730023) Jefferson, AL

(10732003) New Haven, CT

(90091123) Madison, IL

(171190023) Madison, IL

(171191007) Madison, IL

(171192009) Madison, IL (171193007) Clark, IN

(180190006) Dubois, IN

(180372001) Knox, IN

(180830004) Marion, IN

(180970042) Marion, IN

(180970043) Marion, IN (180970066) Marion, IN

(180970078) Marion, IN

(180970079) Marion, IN

(180970081) Marion, IN

(180970083) Tippecan oe,

IN (181570008) Scott, IA (191630019) Daviess, KY

(210590005) Jefferson, KY

(211110043) Jefferson, KY

(211110044) Jefferson, KY

(211110048) Monroe, MI

(261150005)219

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

Oakland, MI (261250001) St. Clair, MI

(261470005) Washtenaw, MI

(261610008) Wayn e, MI

(261630015) Wayne, MI

(261630033) Wayne, MI

(261630036) Jefferson, MO (290990012) Saint

Charles, MO (291831002) St. Louis

City, MO (295100007) St. Louis

City, MO (295100087) Union, NJ

(340390004) New York, NY

(360610128) Butler, OH (3901700 03) Butler, OH

(390170016) Butler, OH

(390170017) Butler, OH

(390171004) Cuyahoga, OH

(390350038) Cuyahoga, OH

(390350045) Cuyahoga, OH (390350065) Franklin, OH

(390490024) Franklin, OH

(390490025) Hamilton, OH

(390610006) Hamilton, OH

(390610014) Hamilton, OH

(390610040) Hamilton, OH (390610042) Hamilton, OH

(390610043) Hamilton, OH

(390617001) Hamilton, OH

(390618001) Jefferson, OH

(390811001) Montgomery,

OH (391130032) Summit, OH (391530017) Allegheny, PA

(420030093) Allegheny, PA

(4200301 16) Allegheny, PA

(420031008) Allegheny, PA

(420031301) Cambria, PA

(420210011) York, PA (421330008) Virginia 13 New Haven, CT (90091123) Baltimore

City, MD (245100040) Baltimore

City, MD (245100049) Hudson, NJ

(340171003) Hudson, NJ

(34017 2002) Union, NJ

(340390004) Bronx, NY (360050080) New York, NY

(360610056) New York, NY

(360610128) Berks, PA

(420110011) Dauphin, PA

(420430401) Lancaster,

PA (420710007) York, PA (421330008) West Virginia 84 Jefferson, AL (10730023) Jeffers on, AL

(10732003) New Haven, CT

(90091123) Cook, IL

(170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL (170311016) Cook, IL

(170312001) Cook, IL

(170313301) Cook, IL

(170316005) Madison, IL

(171190023) Madison, IL

(171191007) Madison, IL (171192009) Madison, IL

(171193007) Clark, IN

(180190006) Dubois, IN

(180372001) Lake, IN

(180890026) Marion, IN

(180970042) Marion, IN (180970043) Marion, IN

(180970066) Marion, IN

(180970078) Marion, IN

(180970079) Marion, IN

(180970081) Marion, IN

(180970083)220

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Nonattainment Sites (Monitoring Site ID)

Tippecanoe, IN (181570008) Scott, IA

(191630019) Jefferson, KY

(211110043) Jefferson, KY

(211110044) Jefferson, KY

(211110048) Baltimore

City, MD (245100040) Baltimore City, MD (245100049) Monroe, MI

(261150005) Oakland, MI

(26125 0001) St. Clair, MI

(261470005) Washtenaw, MI

(261610008) Wayne, MI

(261630015) Wayne, MI (261630016) Wayne, MI

(261630019) Wayne, MI

(261630033) Wayne, MI

(261630036) Jefferson, MO

(290990012) Saint

Charles, MO (291831002) St. Louis City, MO (29 5100007) St. Louis

City, MO (295100087) Hudson, NJ

(340171003) Hudson, NJ

(340172002) Union, NJ

(340390004) Bronx, NY

(360050080) New York, NY (360610056) New York, NY

(360610128) Butler, OH

(390170003) Butler, OH

(390170016) Butler, OH

(390170017) Bu tler, OH

(390171004) Cuyahoga, OH (390350038) Cuyahoga, OH

(390350045) Cuyahoga, OH

(390350060) Cuyahoga, OH

(390350065) Franklin, OH

(390490024) Franklin, OH

(390490025) Hamilton, OH (390610006) Hamilton, OH

(390610014) Hamilton, OH

(390610040) Hamilton, OH

(390610042) Hamilton, OH

(390610043) Hamilton, OH

(390617001) Hamilton, OH (390618001) Jefferson, OH

(390811001) Montgomery, OH

(391130032) Summit, OH

(391530017) Allegheny, PA

(420030008) Allegheny,

PA (420030064) Allegheny, PA (420 030093) Allegheny, PA

(420030116) Allegheny, PA

(420031008) Allegheny, PA

(420031301) Beaver, PA

(420070014) Berks, PA

(420110011) Cambria, PA (420210011) Dauphin, PA

(420430401) Lancaster, PA

(420710007) York, PA

(421330008) Montgomery,

TN (471251009 ) Milwaukee,

WI (550790043) Wisconsin 12 Cook, IL (170310052) Cook, IL

(170310057) Cook, IL

(170310076) Cook, IL

(170311016) Cook, IL

(170312001) Cook, IL

(170313103) Cook, IL (170313301) Cook, IL

(170316005) Lake, IN

(180890022) Lake, IN

(180890026) Scott, IA

(191630019) Wayne, MI

(261630016)221

Table IV.C - 18. Upwind S tate - to -Downwind Maintenance S ite “ Linkages” for 24 -Hour PM2.5 . Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Maintenance Sites (Monitoring Site ID)
Conn ecticut 1 New York, NY (360610062) Delaware 2 Cumberland, PA (420410101) New York, NY

(360610079) Georgia 3 Baltimore City, MD (245100035) Lucas, OH

(390950026) Preble, OH

(391351001)
Illinois 29 District of Columbia (110010041 ) District of

Columbia (110010042) Elkhart, IN

(180390003) Floyd, IN

(180431004) Vigo, IN

(181670023) Muscatine, IA

(191390015) Bullitt, KY (210290006) McCracken, KY

(211451004) Warren, KY

(212270007) Wayne, MI

(261630001) St. Louis

City, MO (2951000 85) New York, NY

(360610079) Cuyahoga, OH (390350027) Cuyahoga, OH

(390350034) Jefferson, OH

(390810017) Lucas, OH

(390950024) Lucas, OH

(390950026) Mahoning, OH

(390990014) Montgomery, OH (391130031) Preble, OH

(391351001) Trumbull, OH

(39155000 7) Allegheny, PA

(420030095) Allegheny,

PA (420033007) Washington, PA

(421255001) Sumner, TN (471650007) Brooke, WV

(540090005) Dane, WI

(550250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027)
Indiana 34 District of Columbia (110010041) Dis trict of

Columbia (110010042) Cook, IL

(170310022) Cook, IL

(170310050) Cook, IL

(170314007) Saint Clair,

IL (171630010) Will, IL (171971002) Muscatine, IA

(191390015) Bullitt, KY

(210290006) McCracken, KY

(211451004) Warren, KY

(212270007) Anne Arun del,

MD (240031003) Wayne, MI (261630001) St. Louis

City, MO (295100085) New York, NY

(360610062) New York, NY

(360610079) Cuyahoga, OH

(390350027) Cuyahoga, OH

(390350034)222

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Maintenance Sites (Monitoring Site ID)

Jefferson, OH (390810017) Lucas, OH

(390950024) Lucas, OH

(390950026) Mah oning, OH

(390990014) Montgomery,

OH (391130031) Preble, OH

(391351001) Trumbull, OH (391550007) Allegheny, PA

(420030095) Allegheny, PA

(420033007) Cumberland, PA

(420410101) Washington,

PA (421255001) Sumner, TN

(471650007) Brooke, WV (54009000 5) Dane, WI

(550250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027)

Iowa 9 Cook, IL (170310022) Cook, IL

(170310050) Cook, IL

(170314007) Will, IL

(171971002) Elkhart, IN

(180390003) St. Louis

City, MO (295100085) Dane, WI (550250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027)
Kansas 2 Muscatine, IA (191390015) Milwaukee, WI

(550790059) Kentucky 33 District of Columbia (110010041) District of

Columbia (110010042) Cook, IL

(170310022) Cook, IL

(170310050) Cook, IL

( 170314007) Saint Clair,

IL (171630010) Will, IL (171971002) Elkhart, IN

(180390003) Floyd, IN

(180431004) Vigo, IN

(181670023) Muscatine,

IA (191390015) Anne Arundel,

MD (240031003) Wayne, MI (261630001) St. Louis

City, MO (295100085) New York, NY

(360610062) New York, NY

(360610079) Cuyahoga, OH

(390350027) Cuyahoga, OH

(390350034) Jefferson, OH (390810017) Lucas, OH

(390950024) Lucas, OH

(390950026) Mahoning, OH

(390990014) Montgomery,

OH (391130031) Preble, OH

(391351001) Trumbull, OH (391550007) Allegheny, PA

(420030095) Allegheny, PA

(420033007) Washington, PA

(421255001) Sumner, TN

(471650007) Brooke, WV

(540090005) Dane, WI (550250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027)223

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Maintenance Sites (Monitoring Site ID) Maryland 5 District of Columbia (1 10010041) District of

Columbia (110010042) New York, NY

(360610062) New York, NY

(360610079) Cumberland,

PA (420410101) Massachusetts 1 New York, NY (360610062) Michigan 28 District of Columbia (110010041) Cook, IL

(170310022) Cook, IL

(170 310050) Cook, IL

(170314007) Saint Clair,

IL (171630010) Will, IL

(171971002) Elkhart, IN (180390003) Vigo, IN

(181670023) Muscatine, IA

(191390015) Warren, KY

(212270007) St. Louis

City, MO (295100085) Cuyahoga, OH

(390350027) Cuyahoga, OH (3903 50034) Jefferson, OH

(390810017) Lucas, OH

(390950024) Lucas, OH

(390950026) Mahoning, OH

(390990014) Montgomery, OH

(391130031) Preble, OH (391351001) Trumbull, OH

(391550007) Allegheny, PA

(420030095) Allegheny, PA

(420033007) Washington,

PA (421255 001) Sumner, TN

(471650007) Brooke, WV (540090005) Dane, WI

(550250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027) Minnesota 4 Muscatine, IA (191390015) Dane, WI

(550250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027) Missouri 20 Cook, IL (170310022) Cook, IL

(170310050) Cook, IL

(170314007) Saint Clair,

IL (171630010) Will, IL

(171971002) Elkhart, IN

(180390003) Floyd, IN (180431004) Vigo, IN

(181670023) Muscatine, IA

(191390015) Bullitt, KY

(210290006) McCracken,

KY (211 451004) Warren, KY

(212270007) Jefferson, OH (390810017) Lucas, OH

(390950026) Montgomery, OH

(391130031) Preble, OH

(391351001) Sumner, TN

(471650007) Dane, WI

(550250047) Milwaukee, WI (550790059) Waukesha, WI

(551330027) Nebraska 2 Mu scatine, IA (191390015) Milwaukee, WI

(550790059)224

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Maintenance Sites (Monitoring Site ID)
New Jersey 5 District of Columbia (110010041) Anne Arundel,

MD (240031003) New York, NY

(360610062) New York, NY

(360610079) Cumberland,

PA (420410101)
New York 9 District of Columbia (1100100 41) District of

Columbia (110010042) Anne Arundel,

MD (240031003) Baltimore

City, MD (245100035) Cuyahoga, OH

(390350027) Cuyahoga, OH

(390350034) Lucas, OH (390950024) Lucas, OH

(390950026) Cumberland, PA

(420410101) North Carolina 3 Baltimor e City, MD (245100035) New York, NY

(360610062) New York, NY

(360610079)
Ohio 29 District of Columbia (110010041) District of

Columbia (110010042) Cook, IL

(170310022) Cook, IL

(170310050) Cook, IL

(170314007) Saint Clair,

IL (171630010) Will , IL (171971002) Elkhart, IN

(180390003) Floyd, IN

(180431004) Vigo, IN

(181670023) Muscatine,

IA (191390015) Bullitt, KY

(210290006) McCracken, KY (211451004) Warren, KY

(212270007) Anne Arundel,

MD (240031003) Baltimore

City, MD (245100035) Wayne, M I

(261630001) St. Louis

City, MO (295100085) New York, NY (360610062) New York, NY

(360610079) Allegheny, PA

(420030095) Allegheny, PA

(420033007) Cumberland,

PA (420410101) Washington, PA

(421255001) Sumner, TN (471650007) Brooke, WV

(540090005) Dane, WI

(550250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027) Pennsylvania 32 District of Columbia (110010041) District of

Columbia (110010042) Cook, IL

(170310022) Cook, IL

(170310050) Cook, IL

(170314007) Saint Clair,

IL (171630010) Will, IL (171971002) Elkhart, IN

(180390003) Floyd, IN

(180431004) Vigo, IN

(181670023) Muscatine,

IA (191390015) Bullitt, KY

(210290006) Warren, KY (212270007) Anne Arundel,

MD (240031003) Baltimore

City, MD (245100035) Wayne, MI

(261630001) New York , NY

(360610062) New York, NY

(360610079)225

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Maintenance Sites (Monitoring Site ID)

Cuyahoga, OH (390350027) Cuyahoga, OH

(390350034) Jefferson, OH

(390810017) Lucas, OH

(390950024) Lucas, OH

(390950026) Mahoning, OH

(390990014) Montgomery, OH (391130031) Preble, OH

(391351001) Trumbull, OH

(391550007) Sumner, TN

(471650007) Brooke, WV

(540090005) Dane, WI

(550250047) Milwaukee, WI (550790059) Waukesha, WI

(551330027)
Tennessee 21 Cook, IL (170314007) Saint Clair,

IL (171630010) Will, IL

(171971002) Elkhart, IN

(180390003) F loyd, IN

(180431004) Vigo, IN

(181670023) Muscatine, IA (191390015) Bullitt, KY

(210290006) McCracken, KY

(211451004) Warren, KY

(212270007) Wayne, MI

(261630001) St. Louis

City, MO (295100085) Jefferson, OH (390810017) Lucas, OH

(390950024) Luca s, OH

(390950026) Mahoning, OH

(390990014) Montgomery,

OH (391130031) Preble, OH

(391351001) Trumbull, OH (391550007) Allegheny, PA

(420033007) Washington, PA

(421255001) Virginia 7 District of Columbia (110010041) District of

Columbia (11001 0042) Anne Arundel,

MD (240031003) Baltimore

City, MD (245100035) New York, NY

(360610062) New York, NY

(360610079) Cumberland, PA (420410101) West Virginia 35 District of Columbia (110010041) District of

Columbia (110010042) Cook, IL

(170 310050) Cook, IL

(170314007) Saint Clair,

IL (171630010) Will, IL

(171971002) Elkhart, IN (180390003) Floyd, IN

(180431004) Vigo, IN

(181670023) Muscatine, IA

(191390015) Bullitt, KY

(210290006) Warren, KY

(212270007) Anne Arundel, MD (240031003) Baltimore

City, MD (245100035) Wayne, MI

(261630001) St. Louis

City, MO (295100085) New York, NY

(360610062) New York, NY

(360610079) Cuyahoga, OH (390350027) Cuyahoga, OH

(390350034) Jefferson, OH

(390810017) Lucas, OH

(390950024) Lucas, OH

(3909500 26) Mahoning, OH

(390990014)226

Upwind State Number of

Linkages Counties Containing Downwind 24 - Hour PM2.5 Maintenance Sites (Monitoring Site ID)

Montgomery, OH (391130031) Preble, OH

(391351001) Trumbull, OH

(391550007) Allegheny, PA

(420030095) Allegheny,

PA (420033007) Cumberland, PA

(420410101) Washington, PA (421255001) Sumner, TN

(471650007) Dane, WI

(550 250047) Milwaukee, WI

(550790059) Waukesha, WI

(551330027) Wisconsin 6 Cook, IL (170310022) Cook, IL

(170310050) Cook, IL

(170314007) Will, IL

(171971002) Elkhart, IN

(180390003) Muscatine, IA

(191390015)227

b. Results of 8
- Hour Ozone Contribution Modeling In this section, we present the interstate contributions from emissions in upwind states to downwind nonattainment and maintenance sites for the ozone NAAQS. As described previously in section IV.B., states which contribute 0.8 ppb or more to 8
- hour ozone nonattainment or maintenance in another state are identified as states with contributions to downwind attainment and maintenance sites large enough to warrant further analysis. We performed air quality modeling to quantify the contributions to 8
- ho ur ozone from emissions in each of the following 37 states individually: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland combined with the District of Columbia, Massachusett s, Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Hampshire, New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, South Dakota, Tennessee, Texas, Vermont, Virginia, West Virginia, and Wi sconsin. We calculated each state’s contribution to each of the 11 monitoring sites that are projected to be nonattainment228

and each of 14 53 sites that are projected to have maintenance problems for the 8
- hour ozone NAAQS in the 2012 Base Case. The maximum contribution from each state to 8
- hour ozone nonattainment in downwind sites is provided in Table IV.C - 19. The maximum contribution from each state to 8
- hour ozone maintenance in downwind sites is also provided in Table IV.C - 19. The contributions from e ach state to all projected 2012 nonattainment and maintenance sites for the 8
- hour ozone NAAQS are provided in the AQMTSD. Table IV.C - 19. Maximum Contribution to Downwind 8 -Hour Ozone Nonattainment and Maintenance for Each of 37 S tates.

Upwind State Max imum Downwind Contribution to Nonattainment for Ozone (ppb) Maximum

Downwind Contribution to Maintenance for Ozone (ppb) Alabama 4.7 4.7 Arkansas 1.4 1.8 Connecticut 1.7 1.6 Delaware 3.3 2.5 Florida 0.8 2.1 Georgia 2.1 1.7 Illinois 0.8 0.6 Indiana 1.1 1.0 Iowa 0.3 0.3 Kansas 0.6 0.8 Kentucky 2.3 1.8

53 For two of the 16 projected maintenance sites (Harris Co., Texas sites 482011015 and 48201 1035) there were less than 5 days with 8
- hour ozone predictions of at least 70 ppb. Thus, we did not calculate contributions for these two maintenance sites.229 Upwind State Max imum Downwind Contribution to Nonattainment for Ozone (ppb) Maximum

Downwind Contribution to Maintenance for Ozone (ppb) Louisiana 11.4 10.6 Maine 0.0 0.0 Maryland 6.0 4.1 Massachusetts 0.6 0.5 Michigan 0.9 0.5 Minnesota 0.1 0.2 Mississippi 5.2 2.5 Missouri 0.7 0.6 Nebraska 0.2 0.2 New Hampshire 0.1 0.1 New Jersey 16.8 15.8 New York 0.4 22.7 North Carolina 1.7 2.0 North Dakota 0.1 0.0 Ohio 2.8 2.6 Oklahoma 2.1 2.7 Pennsylvania 8.9 8.1 Rhode Island 0.1 0.1 South Carolina 0.6 0.8 South Dakota 0.0 0.0 Tennessee 1.6 3.0 Texas 1.6 0.6 Vermont 0.0 0.1 Virginia 4.2 4.5 West Virginia 2.7 2.3 Wisconsin 0.3 0.2230 Based on the state
-by
- state contribution analysis, there are 22 States and the District of Columbia 54 which contribute 0.8 ppb or more to downwind 8
- hour ozone nonattainment. These states are : Alabama, Arkansas, Connecticut, Delaware, the District of Columbia, Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, New Jersey, North Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, and West Virginia. In Table IV.C - 20, we provide a list of the downwind nonattainment counties to which each upwind State contributes 0.8 ppb or more (i.e., the upwind State
- to downwind nonattainment “linkages”). There are 22 States and the District of Columbia which contribute 0.8 ppb or more to downwind 8
- hour ozone maintenance. These states are : Alabama, Arkansas, Connecticut, Delaware, the District of Columbia, Florida, Georgia, Indiana, Kansas, Kentucky, Louisiana, Maryland, Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee,

54 As noted above, we combined Maryland and the District of Columbia as a single entity in our co ntribution modeling. This is a logical approach because of the small size of the District of Columbia and, hence, its emissions and its close proximity to Maryland
. Under our analysis, Maryland and the District of Columbia are linked as significant contr ibutors to the same downwind nonattainment counties.231

Virginia, and West Virginia. In Table IV.C - 21, we provide a list of the downwind nonattainment counties to which each upwind State contributes 0.8 ppb or more (i.e., the upwind State - to - downwind nonattainment “linkages”).232

Table IV.C - 20. Upwind S tate - to -Downwind Nonattainment “ Linkages” for 8 -hour Ozone.

Upwind State Number

of Linkages Counties Containing Downwind 8 - Hour Ozone Nonattainment Sites (Monitoring

Site ID)

Alabama 8 East Baton Rouge, LA (220330003) Brazoria, TX

(480391004) Harris, TX

(482010051) Harris, TX

(482010055) Harris, TX

(482010062) Harris, TX

(482010066) Harris, TX (482011039) Tarrant, TX

(484391002)

Arkansas 3 East Baton Rouge, LA (220330003) Brazo ria, TX

(480391004) Tarrant, TX

(484391002) Connecticut 1 Suffolk, NY (361030009)
Delaware 3 Suffolk, NY (361030002) Suffolk, NY

(361030009) Philadelphia,

PA (421010024) Florida 2 Harris, TX (482010062) Tarrant, TX

(484391002) Georgia 7 Brazoria, TX (480391004) Harris, TX

(482010051) Harris, TX

(482010055) Harris, TX

(482010062) Harris, TX

(482010066) Harris, TX

(482011039) Tarrant, TX (484391002) Illinois 2 Suffolk, NY (361030009) Harris, TX

(482010055)
Indiana 3 Suffolk, NY (361030002) Suffolk, NY

(361030009) Philadelphia,

PA (421010024) Kentucky 6 Suffolk, NY (361030002) Philadelphia,

PA (421010024) Harris, TX

(482010051) Harris, TX

(482010055) Harris, TX

(482010062) Harris, TX

(482011039)233

Upwind State Number

of Linkages Counties Containing Downwind 8 - Hour Ozone Nonattainment Sites (Monitoring

Site ID) Louisiana 7 Brazoria, TX (480391004) Harris, TX

(482010051) Harris, TX

(482010055) Harris, TX

(482010062) Harris, TX

(482010066) Harris, TX

(482011039) Tarrant, TX (484391002) Maryland 3 Suffolk, NY (361030002) Suffolk, NY

(361030009) Phil adelphia,

PA (421010024) Michigan 1 Suffolk, NY (361030009)
Mississippi 8 East Baton Rouge, LA (220330003) Brazoria, TX

(480391004) Harris, TX

(482010051) Harris, TX

(482010055) Harris, TX

(482010062) Harris, TX

(482010066) Harris, T X (482011039) Tarrant, TX

(484391002)
New Jersey 3 Suffolk, NY (361030002) Suffolk, NY

(361030009) Philadelphia,

PA (421010024) North Carolina 3 Suffolk, NY (361030002) Suffolk, NY

(361030009) Philadelphia,

PA (421010024)
Ohio 3 Suff olk, NY (361030002) Suffolk, NY

(361030009) Philadelphia,

PA (421010024) Oklahoma 1 Tarrant, TX (484391002) Pennsylvania 2 Suffolk, NY (361030002) Suffolk, NY

(361030009)

Tennessee 7 Philadelphia, PA (421010024) Brazoria, TX

(480 391004) Harris, TX

(482010051) Harris, TX

(482010055) Harris, TX

(482010062) Harris, TX

(482010066)234

Upwind State Number

of Linkages Counties Containing Downwind 8 - Hour Ozone Nonattainment Sites (Monitoring

Site ID) Harris, TX (482011039)

Texas 1 East Baton Rouge, LA (220330003) Virginia 3 Suffolk, NY (361030002) Suffolk, NY

(361030009) Philadelphia,

PA (421010024) West Virginia 3 Suffolk, NY (361030002) Suffolk, NY

(361030009) Philadelphia,

PA (421010024)
Table IV.C - 21. Upwind S tate - to -Downwind Maintenance “ Linkages” for 8 -Hour Ozone.

Upwind State Number

of Linkages Counties Containing Downwind 8 - Hour Ozone Maintenance Sites (Monitoring Site ID) Alabama 6 DeKalb, GA (130890002) Fulton, GA

(131210055) Harris, TX

(482010024) Harris, TX

(482010029) Harris, TX

(482011050) Tarrant, TX

(484392003) Arkansas 4 Dallas, TX (481130069) Dallas, TX

(481130087) Harris, TX

(482011050) Tarrant, TX

(484392003)
Connecticut 1 Westchester, NY (361192004) Delaware 1 Bucks, PA (420170012) Florida 4 DeKalb, GA (130890002) Fulton, GA

(131210055) Harris, TX

(482010024) Harri s, TX

(482010029)235

Georgia 4 Harris, TX (482010024) Harris, TX

(482010029) Harris, TX

(482011050) Tarrant, TX

(484392003)
Indiana 4 Fairfield, CT (90010017) New Haven,

CT (90093002) Westchester,

NY (361192004) Bucks, PA

(420170012) Kansas 1 D allas, TX (481130069) Kentucky 6 Fairfield, CT (90010017) Fairfield,

CT (90011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) Bucks, PA

(420170012) Louisiana 6 Dallas, TX (481130069) Dallas, TX

(481130087) Har ris, TX

(482010024) Harris, TX

(482010029) Harris, TX

(482011050) Tarrant, TX

(484392003) Maryland 6 Fairfield, CT (90010017) Fairfield,

CT (90011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) Bucks, PA

(420170012) Mis sissippi 7 DeKalb, GA (130890002) Fulton, GA

(131210055) Dallas, TX

(481130087) Harris, TX

(482010024) Harris, TX

(482010029) Harris, TX

(482011050) Tarrant, TX (484392003)
New Jersey 6 Fairfield, CT (90010017) Fairfield,

CT (90011123) Fair field,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) Bucks, PA

(420170012)
New York 5 Fairfield, CT (90010017) Fairfield,

CT (90011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Bucks, PA

(420170012) North Carolina 5 Fairfi eld, CT (90011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) Bucks, PA

(420170012)
Ohio 6 Fairfield, CT (90010017) Fairfield,

CT (90011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) Bucks, PA

(420170012) Oklahoma 3 Dallas, TX (481130069) Dallas, TX

(481130087) Tarrant, TX

(484392003)236

Pennsylvania 5 Fairfield, CT (90010017) Fairfield,

CT (90011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) South Carolina 2 Fulton, GA (131210055) Harris, TX

(482010029) Tennessee 5 DeKalb, GA (130890002) Fulton, GA

(131210055) Bucks, PA

(420170012) Harris, TX

(482010024) Harris, TX

(482011050) Virginia 6 Fairfield, CT (90010017) Fairfield,

CT (90 011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) Bucks, PA

(420170012) West Virginia 6 Fairfield, CT (90010017) Fairfield,

CT (90011123) Fairfield,

CT (90013007) New Haven,

CT (90093002) Westchester,

NY (361192004) Buc ks, PA

(420170012)237

D. Proposed Methodology to Quantify Emissions that Significantly Contribute or Interfere with Maintenance In this section, EPA explains its general approach to quantifying the amount of emissions that represent significant contributi on and interference with maintenance. EPA then applies that approach for the three different NAAQS being address ed in today’s notice: the 1997 o zone NAAQS, the 1997 annual PM2.5 NAAQS and the 2006 24
- hour PM2.5 NAAQS. With respect to the 1997 ozone NAAQ S, we apply this methodology to fully quantify the significant contribution and interference with maintenance for 16 states. We also use the methodology to quantify, for 10 additional states, NO X emissions reductions that are necessary to make measurable progress towards eliminating their significant contribution and interference with maintenance. Additional information gathering and analysis is needed to determine the extent to which further reductions from these states may be needed to fully eliminate
s ignificant contribution and interference with maintenance with the ozone NAAQS. As is further explained in section IV.D.2.b EPA will fully address this issue in a future rulemaking as quickly as possible. With respect to the annual PM2.5 NAAQS, this propo sal finds that 24 eastern states have SO 2 and NO x emission reduction responsibilities . We apply the proposed methodology to fully238

quantify the SO 2 and NOX emissions from each of these states that significantly contribute to or interfere with maintenance i n downwind areas. With respect to the 24
- hour PM 2.5 NAAQS, this proposal finds that 25 eastern states have emissi on reduction responsibilities. We use the proposed methodology to quantify emissions reductions that these states must achieve to make, at a minimum, measurable progress towards eliminating the state’s significant contribution and interference with maintenance. Further analysis will be needed to determine if these reductions are sufficient to fully eliminate any or all of these states’ signific ant contribution and interference with maintenance for purposes of the 24
- hour PM 2.5 standard. As is explained in greater detail in section IV.D.2.a, EPA intends to finalize, to the extent possible a determination of the complete amount of emissions that represents significant contribution and interference with maintenance. If further analysis shows that the amounts of emissions proposed in today’s notice include all emissions that significantly contribute or interfere with maintenance of the 24
- hour PM2 .5 standard or that more SO 2 emissions should be included, we believe that we will be able to issue a supplemental proposal and finalize a rule fully quantifying significant contribution and interference with maintenance with respect to the 24
- hour PM2.5 s tandard. If239

further analysis shows that other reductions should be considered as part of significant contribution or interference with maintenance with respect to the 24
- hour PM2.5 standard these emissions would be fully addressed in a separate rulemaking effort. 1. Explanation of Proposed Approach to Quantify Significant Contribution After using air quality analysis to identify upwind states that are “linked” to downwind air quality monitoring sites with nonattainment and maintenance problems because the upwind states’ emissions contribute one percent or more to the air quality value at the downwind site, EPA quantifies the portion of each state’s contribution that constitutes its “significant contribution” and “interference with maintenance.” This secti on describes the methodology developed by EPA for this analysis and then explains how that methodology is applied to measure significant contribution and interference with maintenance with respect to the PM2.5 NAAQS and the ozone NAAQS. For this portion o f the analysis, EPA expands upon the methodology used in the NOX SIP Call and CAIR, but modifies it in significant respects. In the NO X SIP Call and CAIR, EPA’s methodology relied upon defining significant contribution as those emissions that could be removed with the use of “highly cost effective” controls. In this action, rather than relying240

solely on determining reductions based on “highly cost effective” controls, EPA uses a number of factors that account for both cost and air quality improvement. Fu rthermore, unlike the NOX SIP Call and CAIR where EPA only defined an amount of reductions needed to address significant contribution to nonattainment, EPA is proposing to define an amount of emissions reductions that addresses both significant contributio n to nonattainment and interference with maintenance. The methodology takes into account both the D.C. Circuit Court’s determination that EPA may consider cost when measuring significant contribution, Michigan , 213 F.3d at 679 , and its rejection of the manner in which cost was used in the CAIR analysis, North Carolina , 531 F.3d at 917 . It also recognizes that the Court accepted
-- but did not require
-- EPA’s use of a single, uniform cost threshold to measure significant contribution. Michigan , 213 F.3d a t 679. The methodology defines each state’s significant contribution and interference with maintenance as the emissions that can be eliminated for a specific cost. Unlike the NO X SIP Call and CAIR, where EPA’s significant contribution analysis had a regi onal focus, the methodology used in today’s proposal focuses on state - specific factors. The methodology uses a multi
- step process to analyze costs and air quality impacts, identify appropriate cost thresholds, quantify reductions available in241

each state a t those thresholds, and consider the impact of variability in EGU operations. In step one, EPA identifies what emissions reductions are available at various costs, quantifying emissions reductions that would occur within each state at ascending costs per ton of emissions reductions. For purposes of this discussion, we refer to these as “cost curves”. In step two, EPA uses an air quality assessment tool to estimate the impact that the combined reductions available from upwind contributing states and the downwind state, at different cost -per - ton levels, would have on air quality at downwind monitor sites that had nonattainment and/or maintenance problems. In step three, EPA examines cost and air quality information to identify cost “breakpoints.” Breakpoints are the places where there is a noticeable change on one of the cost curves, such as a point where a large reduction occurs because a certain type of emissions control becomes cost
- effective. EPA then uses
a multi
- factor assessment to determine the amount of emissions that represents significant contribution to nonattainment and interference with maintenance. The factors considered include both the air quality and cost considerations used in developing the breakpoints along with additional air qual ity and cost considerations. This assessment is performed for each242

transported NAAQS pollutant or precursor which EPA has concluded must be regulated due to its impact on downwind receptors. In this rule, as discussed in section IV.B, EPA is proposing to regulate SO 2 and NOX . The methodology also allows EPA, where appropriate, to define multiple cost thresholds that vary for a particular pollutant for different upwind states. In step four, EPA quantifies the emissions reductions available in each “linked” state at the appropriate cost threshold. This information is then used to develop a state “budget,” representing the r emaining emissions for the state in an average year , and to identify a variability limit associated with that budget. These budgets and variability limits are used to develop enforceable requirements under the proposed and two alternative remedy options. State emissions budgets are discussed in section IV.E and the variability limit is discussed in section IV.F. EPA’s proposed meth odology considers both cost and air quality factors to address complex circumstances . We believe it is important to consider both factors because circumstances related to different downwind receptors can vary and consideration of multiple factors can help EPA appropriately identify each state’s significant contribution under different circumstances. For instance, t here may be cases when upwind
s tates contributing to a specific downwind nonattainment area243

have already done a great deal to reduce emissions while the downwind s tate in which the nonattainment area is located has done very little. Conversely, the downwind state may have made large reductions while one or more contributing upwind states may have done very little. There may be cases where some s tates (upwind or downwind) have large emissions (and a correspondingly large impact downwind ) not because their sources are poorly controlled, but because they have a great er number of sources
-- the operation of which is critical to the reliability of th e electric grid. C onversely , there may be cases where a s tate (upwind or downwind) contributes less in total emissions because it has a smaller number of plants, but those plants are poorly controlled and could be controlled at a relatively low cost. Air quality factors alone are not able to discern these types of differences. Using both air quality and cost factors allows EPA to consider the full range of circumstances and state - specific factors that affect the relationship between upwind emissions and downwind nonattainment and maintenance problems. For example, considering cost takes into account the extent to which existing plants are already controlled as well as the potential for, and relative difficulty of, additional emissions reductions. Theref ore, EPA believes that it is appropriate to consider both cost and air quality metrics when quantifying each state’s significant contribution.244

This methodology is consistent with the statutory mandate in section 110(a)(2)(D)(i)(I) which requires upwind s tates to prohibit emissions that significantly contribute to nonattainment or interfere with maintenance in another state, but does not shift the responsibility for achieving or maintaining the NAAQS to the upwind state. In developing and implementing thi s methodology, EPA was cognizant of a number of factors. First, in many areas, transported emissions are a key component of the downwind air quality problem. Second, there are large amounts of low cost emission reduction opportunities in upwind states . Third, EPA recognizes that section 110(a)(2)(D) does not grant EPA authority to require emissions reductions solely because they provide large health and environmental benefits: reductions required pursuant to section 110(a)(2)(D)(i)(I) must be related to the goal of eliminating upwind state emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in downwind areas. Fourth, EPA is cognizant of the relationship between the upwind and downwind state requirements in t he Act. The Act requires upwind states to eliminate significant interstate pollution transport under section 110 ( a )( 2 )( D ). It also requires each state to assure attainment and maintenance of the NAAQS within its borders. Thus, a downwind state must adop t245

controls to demonstrate timely attainment of the NAAQS despite any pollution transport from upwind states that is not eliminated under section 110 ( a )( 2 )( D ) . Given this structure, interpreting significant contribution and interfere with maintenance inher ently involves a policy decision on how much emission s control responsibility should be assigned to upwind states, and how much responsibility should be left to downwind states. In virtually all areas, PM2.5 and ozone problems result from a combination of local, in
- state, and upwind state emissions. EPA’s proposed methodology for determining what portion of a state’s total contribution is its significant contribution and interference with maintenance is intended to assign a substantial but reasonable amount of responsibility to upwind states. There are several reasons that EPA believes upwind state sources contributing to air quality degradation in a downwind state should bear substantial responsibility to control their emissions. First, the plain language of this good neighbor provision requires upwind states to prohibit emissions that significantly contribute to nonattainment or interfere with maintenance in a downwind state. Second, interstate pollution transport increases pollution levels and health r isks in the downwind state. Third, the influx of pollution from upwind states raises the pollution level in a downwind state, making it246

necessary for the downwind state to obtain deeper pollution reductions to attain and maintain air quality standards, wh ich increases costs of control in the downwind state. Fourth, from the standpoint of a downwind state, the pollution contribution of each upwind state adds up to a larger, cumulative degradation of the downwind state’s air quality. Fifth, reducing inters tate pollution enhances prospects that attainment in downwind states can be achieved within the Act’s deadlines and as expeditiously as practicable. All of these points support the position that upwind state sources should bear substantial responsibility to control their emissions. On the other hand, t he proposed methodology ensures that upwind states are not required to shoulder the entire responsibility for the downwind state’s attainment and maintenanc e of the NAAQS. Among other things, our methodology implicitly assumes controls at the same cost per ton level in the downwind state as in the upwind contributing states 55
. In addition, in almost all cases, states with downwind nonattainment and maintenance areas are also required to reduce emissions based on the fact that they are also upwind states

55 We also recognize that there can be reasons to depart from an equal cost per ton allocation of responsibility before a receptor’s attainment and maintenance problem is fully resolved, such as when a re ceptor’s air quality problem has an unusually high local component .247

that are “linked” to other downwind states with nonattainment and maintenance problems. The proposed methodology also directly ties each state’s reduction requirements to EPA’s analysis of that state’s signific ant contribution and interference with maintenance. The required reductions would provide very substantial air quality improvements. For the annual PM2.5 standard, EPA projects that this rule will help assure that all but one area in the East attain the standard by 2014. It will also help a number of areas achieve the standard earlier. The methodology provides similar assistance for ozone, assuring upwind reductions that will mitigate the amount that downwind states may need to do. It reduces ozone con centration levels in 2012 and helps assure that even absent this additional local control, all but 3 areas’ nonattainment and maintenance problems are resolved by 2014. Air quality in the few areas with remaining problems will be improved, providing both health benefits and assistance for these local areas in meeting the NAAQS requirements. a. Step 1. Emissions Reductions C ost Curves The first step in EPA’s methodology for determining the quantity of emissions that represents each state’s significant cont ribution is to identify reductions available at different costs. To do so, EPA developed a set of cost curves that show, at various cost increments, the available emissions reductions248

for EGUs in a state. In other words, EPA determined for specific cost per ton thresholds, the emission reductions that would be achieved in a state if all EGUs in that state used all emission controls and emission reduction measures available at that cost threshold. The zero point of the curve shows what emissions would occur absent any additional investment in emissions reductions (i.e., the base case emissions). Additional points on the curves show the emissions that would occur after the installation of all controls that could be installed at specific cost levels (dollar s per ton of emissions reduced). In developing these cost curves, EPA used IPM to identify costs for reducing emissions from EGUs by modeling emissions reductions available at multiple cost increments. EPA also applied the same cost constraint for each s tate in each modeling iteration. For example, in one iteration, all covered sources in the states examined were constrained to emit at levels achievable by the application of all controls available for $100/ton. In a second iteration, all states examined were assumed to achieve all reductions in each state that were available at $200/ton. The resulting cost curves for SO 2 and annual NO X can be found in section IV.D.2.a of this preamble and the curves for ozone season NO X in section IV.D.2.b. For more de tail on the development of the cost curves, see the TSD,249

“ Analysis to Quantify Significant Contribution ,” in the docket for this rule. Although the cost curves presented in this proposal only include EGU reductions, EPA also conducted a preliminary
asse ssment of reductions available for source categories other than EGUs. This preliminary assessment suggested that there likely would be very large emissions reductions available from EGUs before costs reach the point for which non
- EGU sources have availabl e reductions. EPA therefore initially created cost curves based solely on reductions from EGUs and determined appropriate cost thresholds based on that analysis. EPA then
re - examined non
- EGUs to determine the accuracy of its initial assumptions that ther e were little or no reductions available from non
- EGUs at costs lower than the thresholds that EPA had chosen . EPA’s analysis of the costs of and opportunities for
non - EGU emission reductions is discussed in more detail in section IV.D.3 , later . For the reasons explained in that section, EPA believes there are little or no non
- EGU reductions available at the cost thresholds used in this rule. Therefore, EPA believes it is reasonable at this time to use cost curves that include only EGU reductions. However, EPA is continuing to conduct analyses and believes that it will be necessary to further consider non
- EGU emission reduction opportunities in future transport rules.250

To develop cost curves , emissions available at various costs were assessed in 2012 for ozone season NO X and 2014 for annual NO X and SO 2 . As described in section V.C, EPA coordinated the deadlines for eliminating significant contribution and interference with maintenance with the NAAQS attainment deadlines for downwind states and determined that all significant contribution and interference with maintenance with respect to the 1997 and 2006 PM2.5 NAAQS must be eliminated by 2014, or as expeditiously as practicable. The cost curves show, among other things, that the amount of emissions reduct ions that can be achieved for a given cost var ies over time . This is true because, among other things, c ontrol options that are available in a longer timeframe may not be available in a shorter timeframe. For instance, it takes approximately 27 months to build a flue gas desulfurization unit (FGD, or “ scrubber ”) to reduce SO 2 emissions (Boilermaker Labor Analysis and Installation Timing, USEPA, March 2005) , so if this rule is finalized in mid
2011, emission s reductions from scrubbers by 2012 or 2013 can
o nly reasonably be achieved if that scrubber either exists today, or if it is currently under construction. However, by 2014, additional reductions could be obtained from the construction of new scrubbers. It takes approximately 21 months to construct a s elective catalytic reduction (SCR) unit to reduce emissions of NO X . (Boilermaker Labor Analysis and251

Installation Timing, USEPA, March 2005) Unlike add
- on pollution controls such as scrubbers and SCRs, EPA believes that low
-NOX burners could be installed by 2012 . See TSD, “Installation Timing for Low NO X Burners,” in the docket for this rule. b. Step 2. Performing the Air Quality Assessment In the second step , EPA use s an air quality assessment tool to estimate the impact of the upwind emissions reduct ions on downwind ambient concentrations. 56 This tool is useful for identifying cost breakpoints for significant improvements in downwind air quality changes, including estimated effects on downwind attainment. While less rigorous than the air quality mode ls used for attainment demonstrations, EPA believes this air quality assessment tool is acceptable for assessing the impact of numerous options o n upwind reductions in the process of identifying upwind state significant contribution. It allows the Agency to analyze many more potential scenarios than the time
- and resource
- intensive more refined air quality modeling would permit. This tool assesses the impact that reductions at
56 As is discussed in the RIA, EPA also used the CAMx model to perform air quality analysis of its proposed remedy to address significant contribution. Results from this modeling will not exactly correspond to results from the air quality tool both because the inputs to the air quality modeling are different and the sophisticated model more fully accounts for the complex air chemistry interactions. The full air quality modeling look s at the remedy , including reductions in upwind s tates that do not contribute as well as the impacts of the variability provisions discussed later in this section. It also provides a metric against which to evaluate the air quality assessment tool.252

a given cost breakpoint from all of the contributing states (as well as the sta te with the nonattainment area itself) had on pollutant concentrations at that downwind area. The resulting information is used in step three. For each downwind area with a nonattainment and/or maintenance problem, it shows the total improvement in air quality for each cost level and associated pollutant reduction, the amount of the remaining problem caused by each upwind state (by constituent), and the amount of the remaining problem caused by sources within the state (by constituent). It also shows, overall, how much of the downwind air quality problem had been addressed at different cost levels. More detail on the tool itself, what EPA has done to verify the underlying assumptions, and the specific application of the tool to examining significant cont ribution for ozone and PM2.5 can be found in the TSD, “ Analysis to Quantify Significant Contribution , ” in the docket for this rule. c. Step 3. Identifying Appropriate C ost Thresholds In the third step of this analysis, EPA examines the information developed in the first two steps to identify potential cost thresholds. It then uses a multi
- factor253

assessment to identify which cost threshold 57 or thresholds should be used to quantify states’ significant contribution and interference with maintenance. This n ew methodology responds to the Court’s statements in North Carolina v. EPA both criticizing the manner in which cost was used in the CAIR rule and acknowledging its prior acceptance (in Michigan v. EPA , 213 F.3d 663) of EPA’s use of a uniform cost threshol d and the uniform control requirements associated with the use of such a cost threshold. See North Carolina v. EPA , 531 F.3d at 908, 917.920. In both the NO X SIP Call and CAIR, EPA evaluated the cost of controls relative to the cost of controls required by other CAA regulations to identify a single cost threshold referred to as the “highly
- cost - effective” threshold. In contrast, in this proposed rule, EPA considers multiple factors to identify appropriate cost thresholds , allow ing EPA to give greater wei ght to air quality considerations and mak ing it possible to tailor the significant contribution measurement more closely to different conditions in different groups of states. This step of the analysis begins with an examination of the cost and air qualit y data to identify breakpoints on the

57 The cost t hresholds identified in today’s proposal are specific to the section 110(a)(2)(D) requirements for the states and NAAQS considered in this proposal. They do not represent an agency position on the appropriateness of such cost thresholds for any other appl ication under the Act.254

emissions reductions cost curves developed in steps 1 and 2 related to (1) air quality (e.g., points at which all areas (other than those with an unusually predominant local pollution problem) reach attainment and have maintenance fully addressed), and/or (2) cost (e.g., points at which significant reductions are available because a certain technology is widely deployed). EPA identifies potential breakpoints and then uses a multi
factor assessment to evaluate whether o ne or more of the potential breakpoints represent a reasonable cost at which to define significant contribution for some or all upwind states. The factors in this multi
- factor assessment can be divided into two broad categories: those that focus on air qu ality considerations and those that focus on cost considerations. Air quality considerations include, for example, how much air quality improvement in downwind states results from upwind state emissions reductions at different levels; whether, considering upwind emissions reductions and assumed local (in
- state) reductions, the downwind air quality problems would be resolved; and the components of the remaining downwind air quality problem (e.g., is it a predominantly local or in
- state problem, or does it s till contain a large upwind component). Cost considerations include, for example, how the cost per ton compares with the cost per ton of existing federal and state rules for the same pollutant, and whether the cost per ton is consistent with the255

cost per ton of technologies already widely deployed (similar to the highly
- cost - effective criteria used in both the NO X SIP Call and CAIR); the cost increase required to achieve the next increment of air quality improvement; and whether, given timing consideration s, emissions reductions requirements could be more costly than indicated in the modeling because sources could choose one short
- term solution and then switch to another long
term solution (e.g., switching coals can involve plant modifications. While these costs are low when amortized over a number of years, if a source quickly installs controls, and switches coals again, costs may be higher than projected). Because upwind state sources should bear substantial responsibility for controlling emissions that c ontribute to air quality degradation in downwind states, EPA believes that cost per ton levels that are consistent with widely deployed existing controls, or are within the cost per ton range of controls already required by existing and proposed federal an d state rules (i.e., similar to the highly cost effective concept in the NOX SIP call and CAIR), are reasonable for upwind states from a cost standpoint. Higher cost per ton levels also may be reasonable for upwind states based on examination of air quali ty and cost factors. One reason is that achieving attainment and maintenance of the air quality standard may require controls in256

upwind and downwind states that are more costly than previous controls (particularly if it is a new standard). Based on thi s multi
- factor assessment, EPA identifies a specific cost per ton threshold for quantifying the amount of significant contribution from each state for each precursor pollutant. While we continue to believe that under certain circumstances it may be approp riate for us to use a single uniform cost per ton threshold to quantify significant contribution for all states, we believe it is also important to retain the flexibility to use multiple cost thresholds. For example, we believe it is appropriate to use mu ltiple thresholds where one group of states can, for a lower cost, eliminate nonattainment and maintenance for all the downwind nonattainment and maintenance areas to which they are linked. d. Step 4. Identify Required Emissions Reductions In the final s tep of this analysis, EPA uses the cost thresholds identified in the previous step to determine, on a state -by
- state basis, the amount of emissions that could be reduced at a specific cost. The results of this analysis are used to develop the state budget s and variability limits, which are in turn used to implement the requirements to eliminate significant contribution and interference with maintenance. See
s ections IV.E and IV.F. 2. Application257

The discussion that follows explains how the methodology des cribed previously was applied to quantify significant contribution with respect to the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. EPA also believes that the methodology proposed today could also be used to address transport concerns under other NAAQS, including revisions to the ozone and PM2.5 NAAQS. All of the air quality considerations included in the multi
- factor assessment are based on analysis using the air quality assessment tool. EPA believes that it is appropriate to use this tool because of the advantages it has over more refined air quality modeling to perform analysis of a large number of scenarios very quickly (more refined air quality modeling can take several months, while multiple scenarios can be evaluated using the air quality ass essment tool in a single day). EPA has done more refined air quality modeling of the proposed emissions budgets. The more refined air quality modeling confirms EPA’s overall methodology, but does suggest that, in the case of daily PM2.5 , the air quality assessment tool slightly over
-predicts the air quality benefit of the proposed reductions. For this reason, EPA is also requesting comment on whether we should modify our conclusions regarding the amount of specific states' significant contribution and i nt erference with maintenance; whether there are ways to use our air quality258

modeling in conjunction with the air quality assessment tool to carry out the significant contribution analysis in a way that would not extend the time needed to complete this rulemaking; and whether there are ways to improve the air quality assessment tool. a. Specific Application to PM2.5 (1) Year for Quantifying S ignificant C ontribution EPA’s significant contribution analysis for PM2.5 used a multi
- factor assessment to identify cost thresholds for 2014. EPA believes this is the most appropriate year to consider because it is consistent with attainment dates for both the annual and daily PM2.5 standards. Furthermore, EPA believes that 2014 provides sources sufficient lead time t o install emissions controls or take other actions necessary to achieve the required reductions . After determining the amount of emissions that represents each state’s significant contribution, EPA then considers whether it would be appropriate to establi sh an interim compliance deadline to ensure that the reductions are achieved as expeditiously as practicable. For this part of the analysis, EPA focused on determining what portion of each state’s significant contribution could be eliminated by 2012, the first year in which it would be possible to get reductions following promulgation of this rule in 2011. EPA believes it is possible to achieve much of the required emissions reductions by259

2012. EPA also believes that it is important to get the reductions as expeditiously as practicable and to coordinate the compliance dates both with the downwind states’ maximum attainment deadlines and with the requirement that they eliminate nonattainment as expeditiously as practicable. (2) Step 1. Emissions Reduction s C ost Curves This subsection provides more detail on the cost curves that EPA developed to assess the costs of reducing SO 2 and NOX to address transport related to PM2.5 . It summarizes the information from the curves and then provides EPA’s interpretatio n of that information. EPA uses the information from the cost curves in step 3 to quantify the cost per ton of emissions reductions which should be used to calculate each state’s significant contribution and interference with maintenance, and the resultin g state - specific emissions budgets. To measure significant contribution and interference with maintenance with respect to the PM2.5 NAAQS, EPA developed cost curves showing the annual NO X and annual SO 2 reductions available in 2014 at different cost incr ements. Specifically, EPA developed cost curves that show reductions available in 2014 from EGUs at various costs (in 2006 $) up to $2,500/ton for annual NOX , $5,000/ton for ozone season NO X , and $2,400/ton for SO 2 . For example, this means that EPA exami ned reductions of annual NO X that are available at a cost of $2,500 per ton or260

less. For SO 2 , the projected cost to reduce a ton of emissions considered is $2,400 or less. Table IV.D
- 1 shows the annual NO X emissions from EGUs at various levels of control cost for 2014. Table IV.D - 1 2014 Annual NOX Emissions from Electric Generating Units for each State in the Transport Region at Various Costs (2006 $) per Ton (Thousand Tons) Marginal Cost per Ton: Base

Case Level $500 $1,500 $2,500 Alabama 119 62 62 50 Connecticut 8 8 8 8 Delaware 6 6 6 6 Florida 196 138 113 80 Georgia 48 46 45 45 Illinois 80 56 56 56 Indiana 201 114 114 107 Iowa 68 56 50 47 Kansas 79 38 36 35 Kentucky 149 72 72 71 Louisiana 46 37 37 28 Maryland 36 36 36 36 Massachusetts 13 13 13 13 Michigan 99 68 68 66 Minnesota 55 38 38 38 Missouri 83 82 61 55 Nebraska 53 34 28 28 New Jersey 27 23 23 20 New York 36 35 32 31 North Carolina 63 63 62 61 Ohio 165 104 98 88 Pennsylvania 205 123 122 86 South Carolina 48 36 36 35 Tennes see 69 29 29 29 Virginia 38 37 37 36 West Virginia 100 54 49 45 Wisconsin 55 44 43 41 Total 2,144 1,455 1,375 1,241 Before applying the information in the cost curves in step 3 of the analysis, EPA evaluated the cost curves to better261

understand how reductions at various cost levels reflect changes in the generation mix (e.g., dispatch changes, fuel use changes, or installation or operation of controls). From the cost curves, EPA concluded that in 2014, there are large NO X reductions available at app roximately $500/ton. At costs above $500/ton and up to at least $2,500/ton, potential reductions increase slowly. This is because the base case assumed that sources would not run their SCR units unless they are required to run those SCR units pursuant to mandates other than CAIR (which will be replaced by this rule when it is finalized). This is especially relevant for winter use of SCRs. Even without CAIR, the NO X SIP Call will provide an incentive to run many SCRs. The cost curves demonstrate that man y of these sources would operate their SCR units when emissions reductions that cost $500/ton are required. In addition, at this $500/ton level some additional units would likely install advanced combustion control technology. Below $500/ton, there are very few other NO X reductions. Significant additional reductions would not be achieved without application of controls costing more than $2,500/ton. In 2014, more reductions could be achieved with installation of additional add
- on controls, such as SCR. The cost curves for SO 2 show the same effect as those for NOX (large emissions reductions at relatively low costs and262

additional reductions at relatively high costs) but the effect was not as pronounced. In 20 14, more than 1,000,000 tons of SO 2 reductions can be achieved at a cost of less than $200 per ton. Most of these reductions can be achieved by requiring companies to operate existing scrubbers that they would not have an incentive to run absent the requirements of CAIR. Additional reductions can be achieved at higher costs. For instance, in many cases, companies are currently using lower sulfur coals to comply with CAIR, but there is no guarantee they will continue to do so. Many, but not all, of these reduction opportunities (e.g., operating curr ent equipment and continued use of low sulfur coal) are available at below $500/ton. Table IV.D
- 2, later , shows that in 2014 there are increased SO 2 emission reduction opportunities beyond just operating existing scrubbers and switching to low sulfur coa l. Installation of new scrubbers becomes feasible by 2014, thus increasing reduction opportunities at costs between $500/ton and $2,000/ton (and above).263

Table IV.D - 2 2014 SO2 Emissions from Electric Generating Units for each State in the Transport Region at Various Costs (2006$) per Ton (Thousand Tons) Marginal Cost per Ton: Base

Case Level $100 $200 $500 $1,000 $1,400 $1,800 $2,000 $2,400 Alabama 322 307 257 171 166 146 101 84 71 Connecticut 6 6 6 6 6 3 3 3 3 Delaware 8 9 9 9 9 9 9 8 8 Florida 195 178 171 117 113 111 79 74 70 Georgia 173 166 136 133 117 101 92 86 67 Illinois 200 185 165 165 164 165 161 155 143 Indiana 804 478 433 328 291 284 242 227 190 Iowa 164 140 130 106 105 104 102 101 70 Kansas 65 64 56 49 46 46 33 31 24 Kentu cky 740 275 270 248 196 178 127 115 100 Louisiana 95 95 95 95 95 95 95 82 36 Maryland 45 45 45 45 45 45 42 42 40 Massachusetts 17 18 18 10 10 10 9 9 6 Michigan 276 254 253 214 209 207 177 163 116 Minnesota 62 57 55 49 48 48 48 48 46 Missouri 501 289 238 213 212 212 196 183 94 Nebraska 116 119 113 74 73 71 69 45 33 New Jersey 40 40 27 21 21 20 18 17 14 New York 143 142 143 135 118 114 100 70 63 North Carolina 141 141 141 130 114 104 99 91 63 Ohio 841 583 553 408 294 260 236 221 203 Pennsylvania 9 75 825 441 337 202 175 154 145 125 South Carolina 156 138 137 134 125 83 78 57 42 Tennessee 600 154 131 127 126 108 108 100 79 Virginia 137 134 134 109 106 93 65 54 45 West Virginia 496 179 170 161 160 143 132 119 98 Wisconsin 117 111 108 97 92 89 87 81 64 Total 7,436 5,133 4,435 3,692 3,263 3,025 2,660 2,410 1,912264

(3) Step 2. Air Quality Assessment of P otential Emissions Reductions After developing cost curves to show the state
-by
- state cost - effective emissions reductions available, EPA used the air quality assessment tool to evaluate the impact these upwind reductions would have on air quality in “linked” downwind nonattainment and maintenance areas. This section summarizes the results of that evaluation and provides analysis that informs EPA’s multi
- factor assessment, explained in step 3, later . EPA performed air quality analysis for each downwind receptor with a nonattainment and/or maintenance problem. For each receptor, EPA assessed the air quality improvement resulting when a group of state s, consisting of the upwind states that are “linked” to the downwind receptor (i.e., EPA modeling showed that they exceeded the one percent contribution threshold, based on it’s 2012 linkage analysis), and the downwind state where the receptor is located, all made the emissions reductions that EPA identified as available at each cost threshold (as described previously ). This analysis did not assume any reductions in upwind states covered by this rule but not “linked” to the downwind receptor (even if the s tate was “linked” to a different receptor), beyond those assumed in the base case.265

The percent emissions reductions (and percent air quality improvement) that could be made by each upwind state in 2014 at different cost per ton levels are shown in Figure s IV.D - 1 through IV.D - 4, later . These figures show the percent reduction in SO 2 emissions as a function of cost ( using the emissions at zero dollars per ton in 2014 as the baseline reference ) . A percentage reduction of zero means tha t emissions are not
r educed from the levels that exist at the 2014 zero dollar per ton (base case) cost level. I t is assumed that reduction s in SO 2 emissions are linearly and directly proportional to downwind sulfate contributions . In other words, it is assumed that a specif ic percent reduction in SO 2 emissions would lead to the same percent reduction in air quality sulfate contribution from that upwind state. For example, if a state made a 50 percent reduction in SO 2 emissions, its sulfate contribution to any monitor downwi nd is assumed to be reduced by 50 percent . EPA determines the cumulative air quality improvement that could be expected at a particular downwind receptor by multiplying each upwind state’s percent reduction by its air quality contribution and summing the results for all upwind states. In EPA’s air quality analysis of each downwind receptor, all air quality improvements are measured relative to baseline emissions and air quality contributions in 2012 .266

Figures IV.D
- 1 through IV.D
- 4 show that at increased c osts, there are substantial increased emissions reductions. As explained previously , each decrease in emissions is assumed to lead to a corresponding improvement in air downwind air quality. These changes apply to both the daily and annual PM2.5 NAAQS. While the pattern differs from state to state, many states see noticeable decreases in sulfate contribution for costs of $500/ton or less. Reductions in downwind contribution level off, then many states start to see an additional decrease in contribution at higher costs (in general about $1,500/ton). Figure IV.D - 1 Percent Reduction in Downwind SO2 Contribution as a Function of Cost in 2014 for DE, FL, KS, LA, MA and NE.

-10 0 10 20 30 40 50 60

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Ma rginalcost per ton (EGU SO 2)Percent reduction in 2014 contribution DE FL KS LA MA NE267

Figure IV.D - 2 Percent Reduction in Downwind SO2 Contribution as a Function of Cost in 2014 for AL, CT, MD, MN, NJ and SC.

-10 0 10 20 30 40 50 60

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Margi nal cost per ton (EGU S O2)Percent reduction in 2014 contribution AL CT MD MN NJ SC268

Figure IV.D - 3 Percent Reduction in Downwind SO2 Contribution as a Function of Cost in 2014 for IA, KY, NY, NC, OH, TN and VA.

0 10 20 30 40 50 60 70 80 90

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Marginalcost per ton(E GU SO2)Percent reduction in 2014 contribution IA KY NY NC OH TN VA269

Figure IV.D - 4 Percent reduction in downwind SO2 contribution as a function of cost in 201 4 for GA, IL, IN, MI, MO, PA, WV and WI.

0 10 20 30 40 50 60 70 80 90

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Margi nal cost per ton(E GU S O2)Percent reduction in 2014 contribution GA IL IN MI MO PA WV WI

EPA also identified the overall air quality reductions projected by the air quality assessment tool at downwind nonattainment and maintenance receptor locations. As explained previously , the multi
- f actor assessment in step 3 analyzed the results from the downwind receptor analysis in step 2 for the annual and daily PM2.5 standards. Tables IV.D
- 3 and IV.D
- 4, later , show the air quality improvements in 2014 from the emissions reductions projected to o ccur at various costs. Table IV.D - 4 also shows the average decrease in ambient daily PM2.5 for different sets of downwind sites for various reductions in SO 2 .270 Table IV.D - 3 Estimated Number of Nonattainment and/or Maintenance Monitor Sites in 2014 for Annual PM2.5 (as a Function of SO2 Cost-per - Ton Levels) 58 2014 2014 Marginal Cost per Ton Number of

Remaining Nonattainment Monitor Sites Number of Remaining Nonattainment and Maintenance Monitor Sites $0 12 19 $100 3 6 $200 2 3 $300 2 3 $400 1 2 $5 00 1 2 $600 1 1 $800 1 1 $1,000 1 1 $1,200 1 1 $1,400 1 1 $1,600 1 1 $1,800 0 1 $2,000 0 1 $2,400 0 1

58 NO x Reductions at $500/ton271

Table IV.D - 4 Daily Air Quality Impacts vs. SO2 Cost per Ton Levels in 2014 (also Assumes NOX Control Level at $500/ton) . Marginal SO 2 Co st per ton



### ↓ Number of Remaining Nonattainment and Maintenance Monitor Sites Air Quality I mprovement ( Average ug/m^3 Reduction ) Relative to 2014 B ase C ase (zero dollars/ton) All sites in 2012 base 6 selected sites * 3 selected sites ** $0 64 0.0 0.0 0.0 $100 16 3.7 2.0 1.8 $200 12 4.4 2.4 2.1 $300 8 4.7 2.6 2.3 $400 6 * 5.0 2.9 2.6 $500 6 5.1 3.0 2.6 $600 6 5.3 3.1 2.8 $800 6 5.4 3.3 2.9 $1,000 6 5.6 3.4 3.0 $1,200 6 5.7 3.4 3.0 $1,400 6 5.8 3.5 3.1 $1,600 5 6.0 3.6 3.2 $1,800 4 6.2 3.7 3.3 $2,000 3 ** 6.4 3.9 3.4 $2,400 1 6.8 4.1 3.7 * The six sites are: Allegheny County, PA (2 sites); Baltimore County, MD; Wayne County, MI; Lake County, IN; Cook County, IL. ** The three sites are: Lake County, IN; Cook County, IL; Allegheny County, PA.272 A number of conclusions can be drawn from Tables IV.D
3 and IV.D
- 4. Very low cost SO 2 reductions result in significant air quality benefits. 59 As explained previously , this is because there are significant reductions available from sources that operate ex isting scrubbers and, in a number of cases, use relatively low cost, lower sulfur coal. At the same time, in 2014 enough lead time exists for considerable emission reduction opportunities from new scrubber installations. Other programs are also achieving reductions (for example, some state rules and enforcement consent decrees require SO 2 and NOX reductions in 2013 and 2014). The analysis also shows that higher cost reductions continue to provide downwind air quality improvements. (4) Identifying C ost Thresholds (a) Considerations for 2014 For PM2.5 , EPA considered three cost breakpoints for SO 2 and one for NO X . First EPA looked at a point at which EGUs operated all installed controls, continued to burn coals with sulfur contents consistent with what they were burning in 2009, and operated any additional controls they are currently planning to install by 2014. For NO X , this point
59 Measured in terms of downwind area nonattainment and/or maintenance concerns being addressed . This is also true in terms of improvements in air concentrations of PM2.5 .273

is similar to the $500/ton cost. For SO 2 , it is similar to the $300 to $400 cost. EPA believes this is an appropriate sta rting point, because if a state is “linked” to a downwind state (i.e., if our air quality analysis showed it was contributing above the 1 percent threshold), EPA believes it is appropriate to prohibit that state from increasing its emissions which could wo rsen downwind air quality problems. EPA then considered what additional cost thresholds should be considered. For SO 2 EPA considered two breakpoints: 1) $2,000/ton SO 2 and 2) $2,400/ton SO 2 . EPA’s state -by
- state cost modeling at that point indicates tha t scrubbers would be installed on units generating about 20 GW of electricity. Since slightly over 21 GWs of scrubbers were installed in both 2008 and 2009 ( see EPA Analysis of Alternative SO 2 and NO x Caps for Senator Carper

– July 31, 2009

– Appendix B, p age 14) , EPA believes that it is clearly possible for the power sector to install at least that quantity of scrubbers by 2014. The $2,400/ton SO 2 breakpoint represents the point where analysis from the air quality assessment tool projects that both nonat tainment and maintenance concerns would be fully addressed in all areas, except for Allegheny County, Pennsylvania, when considering reductions from only states that contribute274

more than 1 percent 60
. As is explained later in this section, EPA believes th at the monitor in Allegheny County that remains in non
- attainment is in an area where the air quality problem is primarily local. Since EPA’s analysis suggests that the only remaining non
- attainment problem is primarily local, EPA did not consider higher cost thresholds. EPA did not consider additional cost thresholds for NO X beyond $500/ton because there are minimal additional NO X reductions until one considers cost levels higher than $2,400/ton, and SO 2 reductions are generally more effective than NOX re ductions at reducing PM2.5 . EPA did not consider lower cost thresholds than $2,000/ton for SO 2 because: there are clearly continued air quality benefits at higher costs (as evidenced by increases in average air quality improvements in downwind sites); the re is very little change in the number of downwind nonattainment and/or maintenance sites, indicating that the number of upwind states contributing would not be expected to change much;

60 When considering all reductio ns made, including those by states that contribute less than 1 percent, the air quality assessment tool projects that both nonattainment and maintenance will be fully addressed in all areas except for Allegheny County, PA at $2,000/ton.275

and costs of up to $2,000/ton of SO 2 are reasonable in comparison to o ther existing regulations. First EPA assessed $2,000/ton . Reductions at $2,000/ton would improve air quality at several locations with nonattainment and/or maintenance problems. We also believe that, as explained in the introduction to this section, it i s reasonable to require a substantial level of control of upwind state emissions that significantly contribute to nonattainment or maintenance problems in another state. We believe that $2,000/ton is reasonable for SO 2 considering that this cost per ton l evel is based on EGU control technologies that are proven and already widely deployed. Furthermore, compared to other control measures that address SO 2 , this cost per ton level is relatively low. A survey of the control options that EPA examined in the PM2.5 RIA shows that non
- EGU SO 2 reduction opportunities cost from $2,270/ton to over $16,000/ton. While analysis with the air quality assessment tool shows that a site in Allegheny County, Pennsylvania would be in nonattainment and two other sites
- – Lake County, Indiana and Cook County, Illinois
-- would have maintenance problems, if we assume reductions at $2,000/ton and additional reductions made by states because of their contribution to other downwind sites that do not contribute276

to these three probl em areas, the maintenance problems in Lake County, Indiana and Cook County, Illinois would be resolved and only Allegheny County, Pennsylvania, would continue to have a nonattainment/maintenance problem. Because reductions at $2,000/ton continue to have
s ignificant air quality benefit for downwind sites with nonattainment and/or maintenance problems, it has been demonstrated historically that the amount of control equipment that is projected to be needed at $2,000/ton could be installed in the timeframe re quired and these costs are reasonable when compared to other options to reduce SO 2 . Therefore, EPA believes that requiring a cost threshold of at least $2,000/ton would be appropriate for determining significant contribution. Because our analysis shows that one area ( Allegheny County, Pennsylvania ) would have continuing nonattainment and maintenance problems, EPA continued to perform its multi
- factor assessment for the higher $2,400/ton breakpoint to see if any additional emissions should also be conside red significant. For this receptor monitor, EPA considered the local circumstances in the Liberty
- Clairton area in Allegheny County that were leading to continued nonattainment. It is well
- established that, in addition to being impacted by regional sourc es, the Liberty
- Clairton277

area is significantly affected by a large increment of local emissions from a sizable coke production facility and other nearby sources. ( See http://www.epa.gov/pmdesignations/2006standards/final/TSD/t sd_4.0_4.3_4.3.3_r03_PA_2.pdf ). High concentrations of organic carbon indicate the unique local problem for this location. Because the remaining PM2.5 problem is more local in
n ature than the problem at other receptors, EPA does not believe that it is appropriate to establish a higher cost threshold solely for states that are “linked” to this monitor. (b) Amount of Reductions That C ould B e Achieved by 2012 After determining th at the amount of emissions that can be reduced for $2,000/ton in 2014 is an appropriate quantification of a state’s significant contribution, EPA considered whether any of these emissions reductions could be achieved prior to 2014 . For the reasons that fo llow, EPA concluded that significant reductions could be achieved by 2012 and that it is important to require all such reductions by 2012 to ensure that they are achieved as expeditiously as practicable. While EPA believes that it is not possible to requi re the installation of post combustion SO 2 controls (scrubbers) or post combustion NO X278

controls (SCRs) before 2014 (because it takes about 27 months to install a scrubber and 21 months to install an SCR), EPA believes that there are significant reductions that can occur earlier. For SO 2 , reductions from operating existing scrubbers up to their design removal efficiencies and from the use of lower sulfur coals are possible by 2012. For NO X , reductions from operating existing SCRs on a year - round basis and up to their design removal efficiencies and the installation of limited amounts of low NOX burners are possible by 2012. For this reason, EPA believes it is appropriate to require these emissions to be removed in 2012, consistent with the Act’s requiremen t that downwind states attain the NAAQS as expeditiously as practicable. Section IV.E explains how these 2012 emissions reductions requirements are defined. (c) Off
- ramp for S tates That E liminate Their S ignificant C ontribution for L ess Than $2,000/ton Table IV.D.4, previously , shows that for large numbers of monitoring sites where there are nonattainment and or maintenance problems, those problems are fully resolved before all states achieve all of the emissions reductions that could be achieved at less t han $2,000/ton. EPA used the air quality assessment tool to analyze the impact of requiring all states linked to the downwind state site with279

an air quality problem, as well as the downwind state, to reduce emissions consistent with the levels discussed f or 2012 in section IV.D.2.a (2) , previously . The air quality assessment tool shows that those 2012 reductions will resolve the nonattainment and maintenance problems for all of the areas to which the following states are linked: Alabama, Connecticut, Delaware, the District of Columbia, Florida, Kansas, Louisiana, Maryland, Massachusetts, Minnesota, Nebraska, New Jersey and South Carolina (referred to as group 2 states). EPA also assessed whether, in 2014, the combination of this level of reduction from the group 2 states and the remaining states (referred to as group 1 states) continued to result in all downwind areas
-- except for Allegheny County, Pennsylvania

-- fully addressing their nonattainment and or/maintenance problems, and determined that it did . The states in g roup 1 and g roup 2 are rationally grouped considering air quality and cost. EPA proposes that it would not be appropriate to assign the same cost per ton to g roup 2 and g roup 1 states because a significantly lower cost per ton was suffici ent to resolve air quality problems at all downwind receptors linked to the g roup 1 states. Although states are linked to different sets of downwind receptors, our analysis280

indicated that the cost per ton needed to resolve downwind air quality problems va ried only to a limited extent among states within g roup 1 and among states within g roup 2. The cost per ton did vary greatly between the g roup 1 and g roup 2 states. Limitations on the accuracy of our cost and air quality analyses, and the ruling in the Michigan decision accepting EPA’s prior use of a uniform cost approaches, support the decision to use uniform costs for a group of states. (d) Summary of PM2.5 cost threshold analysis Summary of methodology. In summary, EPA determined that SO 2 emissions that could be reduced for less than $2,000/ton in 2014 should be considered a state’s significant contribution, unless EPA determined that a lesser reduction would fully resolve the nonattainment and/or maintenance problem for all the downwind monitoring
s ites to which a particular state might be linked. For these “group 2 states” EPA is determining that a lesser reduction of SO 2 , based on the amount of SO 2 reductions that can be reasonably achieved by 2012 is appropriate. EPA also determined that all sta tes linked to downwind PM2.5 nonattainment and maintenance problems should be required to achieve those emissions reductions that can be reasonably achieved by 2012. Finally, EPA determined that281

all states linked to downwind PM2.5 nonattainment ( see Table IV.D - 5) and maintenance problems should, by 2012, remove all NOX emissions that can be reduced for less than $500/ton in 2012. Table IV.D - 5 States Covered for SO2 Group 1, SO2 Group 2, and NOX Annual
States Covered SO 2 Group 1 SO 2 Group 2 NOX Annual Alabama √ √ Connecticut √ √ Delaware √ √ District of Columbia √ √ Florida √ √ Georgia √ √ Illinois √ √ Indiana √ √ Iowa √ √ Kansas √ √ Kentucky √ √ Louisiana √ √ Maryland √ √ Massachusetts √ √ Michigan √ √ Minnes ota √ √ Missouri √ √ Nebraska √ √ New Jersey √ √ New York √ √ North Carolina √ √ Ohio √ √ Pennsylvania √ √ South Carolina √ √ Tennessee √ √ Virginia √ √ West Virginia √ √ Wisconsin √ √ TOTALS 15 13 28282 After complet ing the process to propose appropriate state -by
- state cost thresholds, EPA used these thresholds to develop the specific state
-by
- state budgets. This step in the process is fully described in section IV.E. (e) Request for comment on issues related to EPA’s modeling methods EPA believes that the methodology described previously is a sound and analytically efficient approach to addressing the requirements of 110(a)(2)(D)(i)(I) for the PM2.5 standards. While it would be possible for EPA to add additiona l analytical steps to the methodology, and such analyses would provide more information, EPA believes that the methodology selected strikes an appropriate balance between the competing requirements of comprehensive analysis and timely action. EPA believes that the technical analysis completed provides a sound basis for action. EPA also seeks to avoid burdensome technical analyses which could prevent EPA from fulfilling our obligation to the Court to act in a timely way. In this section, EPA generally requests comment on issues related to its efforts to strike an appropriate balance. EPA identifies several areas of recognized limitations on our methodology, and requests comments both on the implications283

of these limitations and on possible options for addressing these limitations without unduly delaying necessary action. ( f ) Use of Air Quality Assessment T ool; Results of More Detailed Air Quality Modeling U sed to Evaluate the T ool As discussed previously, EPA uses a simplified air quality assessment too l, rather than actual air quality modeling, to identify air quality impacts of the options considered. This assessment tool enables efficient evaluation of multiple options quickly. We did, however, conduct more refined air quality modeling of the select emissions budgets and this more detailed modeling serves as a check on the appropriateness of the method. This check confirmed the directional conclusions of the air quality assessment tool and largely confirmed the more detailed results of the air quali ty assessment tool, but raised several issues on which EPA is requesting comment. For the annual PM2.5 standard, the air quality assessment tool projected that, after implementation of the proposed FIPs, only one area (Allegheny County, PA) would have a continuing NAAQS air quality problem under the maintenance criteria. The results of the refined air quality modeling are very similar. This modeling projects similar annual PM2.5 reductions in downwind states and projects that Allegheny County, PA would remain in284

nonattainment and that Birmingham, AL would exceed the threshold for “maintenance” by a slight amount (less than 0.1 ug/m3 ). Given the unique local nature of the Allegheny County, PA receptor ( see discussion previously ), EPA does not believe th at the fact that the air quality assessment tool projects the area to have only a maintenance problem, while the refined air quality modeling suggests that the area would remain in nonattainment, raises any serious issues about the conclusions regarding si gnificant contribution to nonattainment and interference with maintenance with the annual PM2.5 standard. Similarly, because the refined air quality modeling projects that Birmingham, AL will exceed the maintenance criteria by only an extremely slight amo unt and because reductions from nearby point sources will reduce local emissions in the area, EPA does not believe the refined air quality modeling demonstrates that upwind reductions beyond those in the proposed FIPs are required to address significant
co ntribution and interference with maintenance of the annual PM2.5 NAAQS in Birmingham. For these reasons, EPA does not believe that the more refined air quality modeling for the annual PM2.5 standard changes any of EPA’s conclusions with respect to reducti ons required to eliminate significant contribution and interference with285

maintenance with respect to this standard. EPA is, however, taking comment on whether Florida, the one group 2 state that was identified as linked to Birmingham, should be moved from group 2 to group 1. EPA notes that no group 2 states are linked to Allegheny County, PA. For the 24
- hour PM2.5 standard, the simplified air quality assessment tool results suggest that under EPA’s proposed FIPs, only one problem site, Allegheny County, PA, would remain. In contrast, the more refined CAMx air quality modeling results show a greater 24
- hour PM2.5 problem, with 10 nonattainment and 4 maintenance areas. As described later , EPA is evaluating the impact of this refined air quality modeling on the methodology used and the conclusions it has reached regarding significant contribution and interference with maintenance with regard to the 24
- hour PM2.5 NAAQS. EPA has completed some preliminary analysis of the difference between the air quality as sessment tool and CAMx results ( see the TSD s “ Analysis to Quantify Significant Contribution ” and “Air Quality Modeling” ). This analysis suggests that the main difference is that in the winter months, the CAMx modeling shows smaller air quality reductions compared to the assessment tool. This is because the CAMx air quality modeling more accurately286

reflects the complex nature of the winter portion of the 24
- hour PM2.5 problem. Unlike summer days, for which sulfate is the dominant contributor to PM2.5 , sul fate concentrations are typically a lesser contributor to the overall PM2.5 concentrations on winter days. Moreover, for winter days, reductions in this already reduced amount of sulfate appear to be less responsive to reductions in SO 2 than for the summe r days. That is, while for the summer a 50 percent reduction in SO 2 emissions would likely yield a nearly 50 percent reduction in sulfate concentrations, in the winter such a reduction in SO 2 would reduce sulfate by less than 50 percent. Thus, EPA believes that more study of the winter portion of the problem is warranted to address the issues raised by the CAMx modeling. EPA believes it is important to understand the degree to which these winter exceedances are transport
- related or locally generated, and the degree to which upwind states’ emissions of NOX , SO 2 , and other transported pollutants are significantly contributing to these winter exceedances. Because the CAMx results indicate additional nonattainment and maintenance areas compared to the air quality assessment tool, EPA requests comment on whether the $2,000/ton cost cutoff for SO 2 resulting from the assessment tool should be raised to a higher cost cutoff.287

While the CAMx results may suggest that it would be appropriate to use a cutoff greater than $2,000/ton, the results do not suggest that the cutoff could be less than $2,000/ton. Instead, the results confirm the importance of achieving, at a minimum, all reductions available at the $2,000/ton cost threshold. Additionally, EPA is reque sting comment on whether some group 2 states should be moved to group 1. These group 2 states are: Connecticut, Kansas, Maryland, Massachusetts, Minnesota, Nebraska, and New Jersey . These states were all placed in group two because the air quality
asses sment tool indicates that the 2012 reductions will resolve the nonattainment or maintenance problems at all areas to which they are linked. However, for these states, the CAMx modeling indicates that one or more of the states to which they are linked will have continuing nonattainment and maintenance problems after the implementation of the 2012 reductions. EPA also notes that that during the winter, PM2.5 contains a larger nitrate component than in summer months. One reason for this is that some nitrate s that are particles in cooler weather volatize and exist as gases during warmer weather. Given this larger contribution from nitrates in the winter, EPA is also taking comment on288

whether there should be a higher cost threshold for annual nitrogen oxides. This may be appropriate for states that have been identified as contributing significantly to sites that the CAMx air quality modeling continues to show as having a residual nonattainment and/or maintenance concern in 2014. Finally, EPA requests commen t on how and whether EPA should incorporate the use of detailed models such as CAMx into our methodology for significant contribution and interference with maintenance. ( g ) Possibility for Emissions I ncreases in Noncontributing S tates EPA also evaluated whether the proposed rule could cause changes in operation of electric generating units in states not regulated under the proposal (that is states not listed in table IV.D
- 5). Specifically, EPA evaluated whether such changes could lead to increas es in emissions in those states, potentially affecting whether they would exceed the 1 percent contribution thresholds used to identify linkages between upwind and downwind states. ( See sections IV.B and IV.C previously for more discussion of the 1 percen t thresholds). Such changes are possible in part because of the interconnected nature of the country’s energy system (including both the electricity grid and coal289

and natural gas supplies). In addition, our models project that the rule affects the cost o f coal (generally lowering the cost of higher sulfur coals and raising the cost of lower sulfur coals). If these price effects took place and if the rule is finalized as proposed, sources in states not covered by the proposed rule might choose to use high er sulfur coals. Increased use of such coals could thus increase SO 2 emissions in those states. EPA’s modeling confirms this, projecting that, after the proposed rule is implemented in states regulated for SO 2 , emissions in some states not covered by the proposed rule would increase (i.e., their emissions are greater in the control case modeling than in the base case modeling). As shown in table IV.D
- 6, Arkansas, Mississippi, North Dakota, South Dakota, and Texas all exhibit 2012 SO 2 emissions increases over the base case and above 5,000 tons 61 . For reference, we also include the statewide 2012 base case emissions from all sources within the state. Table IV.D - 6 Unregulated States with More than 5,000 Tons of Projected SO2 Increases under the Proposed Transport Rule State 2012 SO 2 Increase from Base Case (thousand tons) 2012 SO 2 B ase C ase Emissions from All Sources (thousand
61 While Colorado i s also a state that may see projected increases in emissions, it was not within the domain the EPA analyzed.290 tons)

Arkansas 32 127 Mississippi 18 81 North Dakota 11 94 South Dakota 6 26 Texas 136 641

Further analysis with the air qua lity assessment tool indicates that these projected increases in the Texas SO 2 emi ssions would increase Texas’s contribution to an amount that would exceed the 0.15 μg/m3 threshold for annual PM2.5 . For this reason, EPA takes comment on whether Texas should be included in the program as a group 2 state. ( h ) Providing Downwind States Fu ll Relief from Upwind Emissions. EPA takes very seriously its responsibility to ensure that upwind reductions are made in a timely way so that downwind states can meet their attainment obligations. EPA recognizes, as discussed previously , that while this proposal fully addresses the annual PM2.5 standard, it may not fully address the 24
- hour PM2.5 standard. Where this may be the case, as explained previously , EPA’s air quality modeling shows that the remaining component of non
attainment is almost entire ly occurring in the winter months. Also as noted previously the atmospheric chemistry related to secondary particle formation, and the relative importance of particle species such as sulfate and nitrate,291

is quite different between summer and winter. Because of this, EPA is moving ahead with further efforts, before the final rule is published, to determine the extent to which this winter problem is caused by emissions transported from upwind states and, if this is the case, to identify the total amount of emissions that represents significant contribution and interference with maintenance. To the extent possible, EPA plans to finalize a rule that fully defines this amount. Based on the information that EPA currently has, EPA believes there are a number o f possible outcomes of this further study. Possible outcomes include: (1) Identification of the additional amount of SO 2 emissions reductions needed to eliminate significant contribution and interference with maintenance from upwind states contributing to the residual 24
- hour PM2.5 problem sites 2) Identification of the additional amount of NO X emissions reductions needed to eliminate significant contribution and interference with maintenance from upwind states contributing to the residual 24
- hour PM2.5 pr oblem sites 3) Identification of another pollutant that should be considered part of significant contribution and292 interference with maintenance for states that contribute to the residual 24
- hour PM2.5 problem sites 4) Determination that the reductions prop osed in today’s rulemaking would fully address significant contribution and interference with maintenance at these sites. If EPA determines that more SO 2 emissions should be considered part of this amount based on the analysis performed for today’s proposa l, EPA believes that the next set of emissions that can be reduced above the $2,000/ton threshold would likely still come from the power sector. If EPA determines that more SO 2 emission reductions are required or that the amount of emissions of SO 2 and NOX that it has proposed as significantly contributing to nonattainment are the appropriate amounts to address this winter portion of the problem, EPA intends to supplement today’s proposal and finalize a rule that would fully addresses emissions that signif icantly contribute to or interfere with maintenance of the 2006 daily PM2.5 standard. To the extent that EPA determines that more NO X reductions are needed or that reductions of another pollutant are needed, EPA believes that we could293 provide the greatest assistance to states in addressing transport by finalizing this rule quickly and promulgating a separate rule to achieve any necessary additional NO X reductions. This is because those emission reductions would likely involve placing reduction requirements on sources other than EGUs and that additional app r oaches would need to be addressed. EPA believes that developing supplemental information to address these sources and concepts would substantially delay publication of a final rule, beyond the anticipate d publication of spring 2011. EPA plans to move forward aggressively in the event that these further reductions are needed. We do not, however, intend to delay the reductions in this proposed rule because those reductions have a substantial impact on st ates’ abilities to attain the NAAQS in the required time period and have large health benefits. b. Specific Application to Ozone This section discusses, for the 1997 ozone standards, how EPA applies its multi
- step methodology for defining each state’s si gnificant contribution. For some aspects of the methodology, further work is needed to complete the294

methodology for ozone and this further work will be completed in a separate proposal. ( 1 ) Years for Quantifying S ignificant C ontribution In this subsect ion, we discuss how EPA identifies for ozone the years to analyze for eliminating significant contribution. Similar to the previous discussion for PM2.5 , EPA believes that the selection of the year for eliminating significant contribution is informed by t he attainment deadline and by the Act’s requirement to attain the NAAQS “as expeditiously as practicable.” As noted earlier, the 2012 ozone season is the last ozone season before the 2013 attainment deadline for ozone areas classified as “serious” for the 1997 ozone air quality standards. Thus, for all states “linked” to “serious area” locations for which 2012 is the latest ozone season prior to their attainment deadline, EPA believes that 2012 is the appropriate year for eliminating significant contribu tion, to the extent that purpose can be achieved given the short time period. Because this proposed rule would not be finalized until 2011, the year 2012 also represents the earliest time by which emissions reductions could be achieved, which is consisten t with statutory provisions calling for downwind states to achieve attainment “as expeditiously as practicable.” This also is295

relevant for certain other areas with lower ozone classifications that are projected in our analysis to have continuing air quali ty problems and to be affected by transported pollution from certain upwind states in amounts greater than the 1 percent threshold. 62 EPA is concerned that the timing of this rule presents difficult challenges in eliminating significant contribution and interference with maintenance with regard to the 1997 ozone NAAQS by the attainment date. For states with a 2012 (or earlier) attainment date for which we project continuing ozone problems, we are concerned that strict adherence to a 2012 date for reducti ons could be viewed as an artificial constraint on our ability to require appropriate reductions. EPA believes that the current situation for ozone, involving a transport rulemaking within months of the attainment date (and in a number of cases, after the current attainment date) is a unique situation created by the Court’s remand of the CAIR. Under normal circumstances adhering to the CAA schedule for addressing transport within 3 years after a NAAQS is

62 This is possible where: (1) latest monitoring data indicate attainment of the 1997 ozone standard, (2) the area is operating under one
- year exte nsions of their 2009 deadline, or (3) EPA has not made a formal finding of failure to attain.296

promulgated, transport requirements would be in pla ce years before the attainment date. For purposes of our analysis of ozone for areas with a 2012 attainment date, EPA proposes that we should not be constrained to only considering those reductions that are possible by 2012. Another reason that it woul d be inappropriate to limit upwind state responsibility based on the downwind area’s current attainment date is that the statute contains provisions for extension of attainment dates. To the extent that downwind states have continuing ozone air quality pr oblems after 2012, the Act requires that they be reclassified, which allows the downwind area to qualify for a later attainment date that is as expeditious as practicable but no later than 2019 (2018 emissions year) 63
. In addition, two 1
- year attainment da te extensions can be granted if an area comes close to attaining, based on specific criteria. In addition, history shows many examples of states not meeting air quality standards by their attainment deadlines, often due in part to interstate pollution transport. Even if a downwind area attains on time, further upwind reductions may be important to assure continued maintenance of the standard.
63 In the case of PM2.5 , under subpart I, areas can qualify for an extension beyond 5 years, to as many as 10 years, based on certain statutory criteria.297 If in determining upwind state reduction responsibilities EPA were to automatically assume that downwind states will attain on time despite pollution transport, this assumption would have the effect of absolving the upwind state of responsibility for any reductions in pollution transport that could not be achieved by the downwind area’s current attainment date. EPA does not believe this would be appropriate. This would transfer emissions control responsibility from the upwind state to the downwind state in any case when the area did not attain by its current attainment date, and could delay for years the date when the public would breathe air that meets health
-based standards. Accordingly, for all the reasons discussed prev i ously , we address both 2012 and 2014 in our analysis, and we do not believe that examining 2012 only would be appropriate. EPA has chosen to ex amine 2014 air quality results because, based on a conservative estimate, 2014 is the earliest year for which significantly more stringent NO X limits (e.g., reflecting SCR) could conceivably be considered in a swift, subsequent rulemaking. One area in the eastern half of the U.S. covered by this proposal, Houston, is classified as “severe.” For Houston, it is relevant to consider both that (1) the298

latest permissible attainment date for severe areas is June 2019, which would require emissions reductions b y the 2018 ozone season, and (2) the state implementation plan must provide for attainment as expeditiously as practicable. In light of this, EPA may select a year between 2012 and 2018 that is as expeditious as practicable as the appropriate year for eliminating significant contribution. Because, as explained later , further analysis is needed to quantify any additional reductions necessary to eliminate significant contribution to Houston, EPA requests comment on which year we should select within this 20 12 to 2018 time period for this analysis. ( 2 ) Step 1. Emissions Reductions C ost Curves for EGU O zone S eason NO X Using IPM, EPA developed cost curves for 2012 for ozone season NO X, showing the ozone season (May
- September) NOX reductions available in 20 12 at different cost increments. Specifically, EPA developed cost curves that show reductions available in 2012 from EGUs at various costs (in 2006 $) up to $5,000/ton. These EGU cost curves are presented in Table IV.D
- 7. Generally, projected emissions reductions for 2012 are modest because, by 2012, it is not feasible to install add
- on equipment. Some highly effective and widely employed NO X control299

technologies such as SCR could not be planned and installed in significant numbers within a 1
- year time period (i.e., because a single SCR unit on average takes 21 months to install 64 , SCR-based limits in 2012, if feasible at all, would require an unacceptably steep cost premium). For some states (particularly those which are not regulated by the NO X SIP Ca ll) EPA identified potential reductions from the installation of some combustion controls/low NO X burners and the use of existing SCR units that, in the absence of CAIR, would not be required to operate. These reductions are available at approximately $50 0/ton in 2012. There were very few emissions reductions available below this cost. Table IV.D - 7 2012 Ozone - season NOX Emissions from Electric Generating Units for each State at Various Costs (2006 $) per Ton (thousand tons) Marginal Cost per Ton: $0 $5 00 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $5,000
Alabama 30 30 30 30 30 30 30 29 29 Arkansas 21 11 11 11 11 11 11 11 11 Connecticut 3 3 3 3 3 3 3 3 3 Delaware 2 2 2 2 2 2 2 2 2 Florida 101 74 60 59 59 59 59 58 57 Georgia 35 33 33 33 33 33 33 33 33 Illinois 24 24 25 25 25 25 25 25 25 Indiana 51 50 49 48 47 47 47 46 46 Kansas 31 15 15 15 14 14 14 14 14 Kentucky 31 31 30 30 30 30 29 29 29 Louisiana 22 17 17 17 17 17 17 17 17
64 Estimate from EPA report, ‘‘Engineering and Economic Factors Affecting the Installation of Control Technologies for Multi
- Pollutant Strategies,’’ CAIR docket no. OAR

– 2003

– 0053

– 0106).300

Maryland 14 14 14 14 14 14 14 14 14 Michigan 30 30 30 30 30 30 29 28 28 Mississippi 17 8 8 8 8 8 8 8 8 New Jersey 7 7 7 7 7 7 7 7 7 New York 16 16 16 16 16 16 16 16 16 North Carolina 27 27 27 27 27 27 27 27 27 Ohio 42 41 41 41 41 42 42 42 42 Oklahoma 43 27 27 27 27 26 26 26 26 Pennsylvania 51 51 51 51 50 50 50 50 48 South Carolina 16 16 16 15 15 15 15 15 15 Tennessee 12 12 12 12 12 12 12 12 12 Texas 79 67 67 67 67 66 66 66 66 Virginia 18 18 18 18 18 18 17 17 17 West Virginia 24 24 23 23 22 23 22 22 18 Total 746 648 632 628 625 622 620 618 609
As discuss ed in section IV.D. 3 later , little or no ozone season NO X reductions are available for non
- EGU sources from control measures costing less than $500/ton. Therefore EPA believes its cost curves, which include EGUs only, are complete up to $500/ton but are n ot complete at costs greater than $500/ton. For this reason, we are not addressing in this proposal whether cost per ton levels higher than $500/ton are justified for some upwind states and downwind receptors for ozone purposes. However, we are presenting the information we have on potential EGU reductions at higher cost levels for informational purposes. EPA intends to develop similar emissions reductions and cost information for sources other than EGUs and, in a future rulemaking, to301

consider whether or not reductions at a higher cost per ton are warranted for EGUs and other source categories. EPA developed EGU emissions reductions cost curves for 2014 as well as 2012. EPA believes it is useful to understand and display emissions reductions capabiliti es for 2014, the first year for which further emissions reductions could be achieved through the installation of add
- on controls such as SCR. These 2014 ozone season emissions cost curves are presented in Table IV.D
- 8. The 2014 results have similarities to the 2012 results in that there is an initial drop in emissions when controls are applied at costs of $500 per ton, which represents the use of SCR units in states that would not be mandated to so. Also similar to the 2012 results, relatively few reduct ions are seen between $500/ton and $2,500/ton. In contrast to the 2012 results, add
- on controls become feasible in 2014 at costs between $2,500/ton and $5,000/ton and more EGU emissions reductions are possible at those cost levels. Table IV.D - 8 2014 Ozone - season NOX Emissions from Electric Generating Units for each State at Various Costs (2006$)

per Ton (thousand tons) Marginal Cost per Ton: $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $5,000
Alabama 27 27 27 27 27 27 27 26 26 Arkansa s 22 12 12 12 12 11 11 11 12 Connecticut 3 3 3 3 3 3 3 3 3 Delaware 2 3 3 3 3 3 3 3 3 Florida 95 72 58 57 57 56 53 43 37302

Georgia 22 20 20 20 20 20 20 20 19 Illinois 24 24 24 24 24 24 24 24 24 Indiana 49 48 48 47 47 47 46 44 43 Kansas 35 16 16 16 16 16 16 15 15 Kentucky 30 30 30 29 29 29 29 29 28 Louisiana 21 17 17 17 17 17 17 13 13 Maryland 15 15 15 15 15 15 15 15 15 Michigan 30 30 30 30 29 29 29 29 28 Mississippi 17 8 8 8 8 8 8 8 7 New Jersey 10 10 10 10 10 10 10 10 9 New York 17 17 17 16 16 16 15 15 15 North Carolina 27 27 27 27 27 27 27 27 26 Ohio 45 44 43 43 42 42 42 41 38 Oklahoma 39 24 24 24 24 23 23 23 20 Pennsylvania 53 53 52 52 52 52 52 52 41 South Carolina 16 16 15 15 15 15 15 15 15 Tennessee 12 12 12 12 12 12 12 12 12 Texas 80 69 68 68 67 66 66 66 66 Virginia 16 16 16 16 16 16 16 16 15 West Virginia 24 24 24 21 22 20 20 19 19 Total 732 639 621 614 610 604 598 579 547 ( 3 ) Step 2. Air Quality As sessment of P otential 2012 Emissions Reductions EPA uses an air quality assessment tool for ozone to assess the effect of NO X reductions on downwind ozone concentrations. This air quality assessment tool assumes a linear relationship between the reduction in an upwind state’s ozone season NO X reductions and the reduction in that sta te’s contribution to downwind ozone levels. For example, if a given upwind state reduced its ozone season NOX emissions by 20 percent, the air quality assessment tool estimates that there would also be a 20 percent reduction in the state’s contribution to downwind ozone. Using this303

assessment tool, EPA projected the air quality impact of the emissions reductions at the $500/ton NO X level, the level for which we have complete estimates of potential emissions reductions. The assessment shows significant improvements in 2012 at downwind air quality locations, as evidenced by a reduction in the number of nonattainment and maintenance locations. EPA presents these 2012 ozone season results in Table IV.D
- 9. EPA also includes in Table IV.D
- 9 results for 2014 before and after the imposition of currently installed controls (that is, for the base case or zero dollars per ton, and for the case for which all controls are applied up to $500/ton). Because there are substantial reductions in ozone season NO X from mobile source fleet turnover between 2012 and 2014, there are correspondingly substantial improvements in ozone in the base case, even in the absence of additional EGU or other stationary source controls. Additionally, in this 2014 analysis, when these mobi le source reductions are combined with EGU reductions at $500/ton, the simplified air quality assessment tool projects that almost all sites, with the exception of Houston, TX (nonattainment) and Baton Rouge, LA (maintenance), have resolved their ozone problems.304

Table IV.D - 9 Estimated Number of Remaining Nonattainment or Nonattainment and Maintenance Monitor Sites in 2012 and 2014 as a Function of Ozone - season NOx Cost per Ton Levels.

2012 2012 2014 2014 Margina l Cost per Ton Number of

Remaining Nonatta inment Monitor Sites Number of Remaining Nonattainment and Maintenance Monitor Sites Number of Remaining Nonattainment Monitor Sites Number of Remaining Nonattainment and Maintenance Monitor sites $0 11 25 4 (all in Houston, TX) 7 (Houston,

TX; Baton Rouge, LA) $500 10 19 1 7 ( 4 ) Step 3. Selection of C ost Thresholds, T aking I nto Account C ost and Air Quality C onsiderations Using the multi
- factor cost and air quality methodology described in section IV.D.1, EPA identifies, for a number of states, the 201 2 emissions reductions that eliminate the significant contribution to nonattainment of the 1997 ozone NAAQS and interference with maintenance to the 1997 ozone NAAQS. ( a ) Cost considerations As discussed previously, $500/ton represents the cost level f or which EPA has complete information across source categories and represents the level for which significant emissions reductions are available in 2012. Large additional reductions in 2012 cannot be achieved given the insufficient amount of time for sour ces to install305

controls. Compared to NO X reduction levels determined to be highly cost effective in both the NO X SIP Call and the CAIR, $500/ton is a very low cost for requiring ozone season NOX reductions, and reductions at this level show measurable downwind air quality benefit. EPA believes that $500/ton continues to be an extremely cost effective level for NO X control relative to benchmarks provided by the cost per ton of NOX reductions in existing rules or available from technologies in various secto rs, and the $500/ton level is based on proven and widely deployed technology. Considering the upwind
- downwind state policy considerations discussed previously , $500/ton NO X clearly is not an unreasonable cost level of control for all upwind states that c ontribute more than threshold amounts to ozone air quality problems in downwind states. EPA believes that on purely reasonableness or highly cost effective grounds, a value considerably greater than $500/ton could be justified. EPA notes that the $2,000 /ton threshold for highly cost effective ozone season NO X controls for the NO X SIP call was calculated based on 1990 dollars. If this threshold were updated based on a more recent year, such as the 2006 year used for recent EPA RIA documents, the $2,000/t on threshold would become approximately $3,200 per ton. As a result, EPA believes306

that controlling to at least this level should be considered, unless air quality considerations suggest an “off
- ramp” at lower cost levels. (b) Air Quality C onsiderations Usin g the air quality assessment tool, EPA determined that emissions reductions from ozone season NO X controls at $500/ton would have a significant reduction in nonattainment and maintenance receptors in 2012. Accordingly, EPA believes that requiring the redu ctions that can be achieved at $500/ton are justified based upon the 2012 air quality results. EPA proposes, as discussed previously , that EPA is not artificially constrained in considering reductions beyond 2012 and that it is relevant to address possib le air quality impacts of additional emissions reductions that could be achieved by 2014, the first year for significant additional controls. At the same time, EPA proposes that while 2014 is a relevant year to consider, it is also relevant to consider the nature of the air quality problem in 2014 even in the absence of further transport controls that could be achieved by that date. Taking all of these 2014 considerations into account, the air quality assessment tool results show that in 2014 ozone problems remain only for locations in Houston and Baton Rouge.307

Thus, EPA believes that additional post
- 2012 controls, beyond the $500/ton reductions that are justified based on 2012, are possibly warranted for states that are linked to Houston and Baton Rouge. ( See also discussion later on the issue regarding New York City raised by air quality modeling results.) ( c ) Proposed C ost Threshold for O zone Based on the cost and air quality considerations, EPA proposes $500/ton as the appropriate cost threshold for the following states which contribute to downwind nonattainment and/or maintenance problems in 2012, but which are not linked to ozone air quality problems in either Houston or Baton Rouge: Connecticut, Delaware, the District of Columbia, Indiana, Iowa, Kansas, Maryland, Massachusetts, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Virginia, and West Virginia. For states linked to ozone air quality problems in Houston or Baton Rouge, EPA has not yet identified a cost th reshold for eliminating significant contribution. EPA does, however, propose to find that those states must make at least all of the reductions that can be achieved for $500/ton in 2012. These states are: Alabama, Arkansas, Florida, Georgia, Illinois, Kentucky, Louisiana, Mississippi, Tennessee, and Texas. For these states, the308

$500/ton threshold represents emissions reductions that EPA believes are an essential part of the ultimate emissions reductions amount that will be required to eliminate the sign ificant contribution and interference with maintenance. This level does not represent a complete significant contribution determination for these states because neither the analysis of costs up to $500/ton, nor the analysis of air quality impacts of the c orresponding emissions reductions, suggest that those reductions necessarily represent all reasonable upwind state reductions. For the reasons stated previously in subsection 2.b, EPA believes it is appropriate and consistent with the statutory mandate to consider whether section 110(a)(2)(D)(i)(I) requires further reductions from these states after 2012 for purposes of the 1997 ozone standard. To determine whether further reductions are warranted, EPA is expeditiously conducting further analysis. EPA is continuing to develop and evaluate NO X control costs, emissions reductions, and air quality impact information for NOX controls greater than $500/ton, and to examine facts involving Houston and Baton Rouge, to support a complete determination of significan t contribution and interference with maintenance for states that contribute to one or both of those areas . Based on the analysis done for today’s309

proposal, EPA believes that any additional NO X reduction requirements would involve reductions from sources b eyond EGUs. If this is the case, EPA believes it is likely that we could provide the greatest assistance to states in addressing transport by promulgating a separate rule to achieve those NO X reductions. EPA believes that developing supplemental informat ion to address these sources beyond EGU s would substantially delay publication of a final rule, beyond the anticipated publication of spring 2011. While EPA intends to move forward aggressively on this issue in gathering the necessary information, EPA doe s not believe that this effort should delay the reductions and large health benefits associated with this proposed rule. EPA fully intends to proceed with additional rulemaking to fully address the residual significant contribution to nonattainment and in terference with maintenance as quickly as possible. ( 5 ) Request for C omment C oncerning New York City and C ontributing S tates As in the case of PM2.5 , EPA has done additional refined air quality analysis of a 2014 scenario that assumes implementation of the proposed ozone season NO X emissions reductions, that is, the reductions that would be achieved based on the $500/ton NO X cost threshold. This air310

quality analysis, conducted with the CAMx model, can be compared to the results using the air quality asses sment tool. The CAMx modeling demonstrated that the required NO X reductions would assist many downwind areas with achieving and maintaining the NAAQS. The CAMx air quality modeling for 2014 confirmed the conclusion that Houston and Baton Rouge would cont inue to have nonattainment/maintenance concerns even with the reduction of NO X emissions that could be reduced for less than $500/ton. The modeling also showed that the locations within the New York City nonattainment area would continue to have a mainten ance problem despite the modeled reductions (including those in New York S tate). That is, the New York City area is possibly at risk of being in nonattainment in light of historical year
- to - year variability in ozone levels in the New York City area. For that reason, EPA is taking comment on whether it should consider and analyze the NO X reductions that can be achieved for greater than $500/ton in states that are linked to the New York area sites. These states include: Connecticut, Delaware, Indiana, Ken tucky, Maryland, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia, and West Virginia. If EPA were to conclude that additional analysis is necessary, it would present the results of this in a future notice that would also consider311

whether and to wh at extent states linked to New York City, Houston, and Baton Rouge should be required to make additional NO X reductions in order to eliminate all significant contribution with respect to the 1997 ozone NAAQS. 3. Discussion of C ontrol C osts for S ources O ther than EGUs Previously in this section ( see discussion in IV.D.2 previously ) EPA discusses its proposed cost criteria for identifying SO 2 and NOX emissions reductions necessary to eliminate at least part of each state’s significant contribution and to eliminate at least part of each upwind state’s interference with maintenance of the PM2.5 NAAQS. In addition, EPA discusses interim cost criteria for ozone. Consistent with these criteria, EPA does not believe that other source categories have emissions tha t are currently significantly contributing to nonattainment or interfering with maintenance of the 1997 and 2006 PM2.5 NAAQS. Thus, with respect to the 1997 and 2006 PM2.5 NAAQS, we are not proposing to include in the FIPs emissions reductions requirement s for other source categories. (a) SO 2 So urces and C osts As described previously , EPA is proposing to define significant contribution on the basis of cost informed by air quality impacts, and to conclude $2,000/ton represents312

the highest cost value necessa ry for SO 2 to eliminate significant contribution and interference with maintenance. For SO 2 , as described previously, EPA is proposing to conclude that significant contribution and interference with maintenance would be eliminated at costs of no more than $2,000/ton, and in some states, at lower costs. The EPA has not identified SO 2 reductions for sources other than EGUs at less than $2,000/ton (in year 2006 $). For the CAIR, EPA included a technical support document 65 which noted that for SO 2 , EGUs were t he dominant contributor to transported emissions, but that there were a few additional categories for which regional emissions exceeded 1 percent of the overall inventory in the eastern half of the U.S. EPA has updated this analysis with a review of the year 2012 inventory, with similar conclusions. See TSD

– “Non
- EGU Emissions Reductions Cost and Potential.” The highest
- emitting categories of non
- EGU SO 2 emissions are: (1) industrial, commercial, and institutional (ICI) boilers, (2) Portland cement
manu facturing, (3) petroleum refining, and (4) sulfuric acid manufacturing.

65 Identification and Discussion of Sources of Regional Point Source NOX and SO2 emissions other than EGUs. EPA/OAQPS and CAMD. January 2004.313 For ICI boilers, most of the SO 2 emissions are from coal
- fired boilers, and to a lesser degree from residual or distillate oil
- fired boilers. Possible ways to reduce SO 2 emissions from ICI boilers include fuel switching, flue gas desulfurization, and dry sorbent duct injection. Because of variability in operations, it is difficult to identify precise cost per ton estimates for fuel switching and sorbent injection. For industrial boil ers, the capacity factor (that is, the fraction of boiler capacity that is used in a year) can have a significant impact on the cost per ton estimate. Regarding flue gas desulfurization, a recent report prepared by NESCAUM66 suggests scrubber costs are typ ically well above $2,000/ton for ICI boilers. For Portland cement manufacturing, information from a 2006 report prepared by the Lake Michigan Air Directors Consortium (LADCO) estimated costs for SO 2 scrubbing to be between $ 2 , 211
- 6,917 per ton (in yea r 2003 $). The LADCO “white papers” discussion is available from the following website: http://www.ladco.org/reports/control/final_reports/identifi

66 Reference: NESCAUM Applicability and Feasibility of NO X , SO2 , and PM Emissions Control Technologies for Industrial, Commercial, and Institutional (ICI)Boilers. NESCAUM, November 2008. pp. xvii, 3
- 12
- 13.314

cation_and_evaluation_of_candidate_control_measures_ii_june _2006.pdf . For petroleum refining, the largest sources of SO 2 emissions are from catalytic cracking, sulfur recovery units, and process heaters. For each of the sources in the petroleum refining sector, EPA believes that SO 2 controls less than $2,000/ton will generally not be available at refineries c overed by the recent settlement agreements EPA has entered into with numerous petroleum refineries. Moreover, such agreements cover 88 percent of U.S refining capacity, and will lead to up to 250,000 tons of SO 2 emissions reductions annually. Compliance with these agreements has already taken place at most affected refineries, and these reductions are generally reflected in
our 2012 base case emissions inventory. 67 For sulfuric acid manufacturing, the SO 2 emissions are related to the percent recovery of sulfuric acid product. Because the percent recovery is plant
- specific, the available emissions reductions and the cost per ton of controls are highly variable. At the time of the CAIR, EPA made rough calculations that the then
- existing 126,000 tons

67 U.S. EPA. Petroleum Refinery National Priority Case Results. Available at http://www.epa.gov/compliance/resources/cases/civil/caa/oil /index.html .315

of SO 2 would be reduced by about one
- half if all of the sulfuric acid manufacturing in the eastern U.S. was controlled to meet the NSPS level of 4 pounds of SO 2 per ton of product. EPA did not develop cost estimates for these approximate reductions and such co st estimates are still not available. EPA notes, however, that it has entered into a number of settlement agreements with sources in the sulfuric acid production industry, and a significant amount of the estimated available reductions has already been
rea lized. Over 36,000 tons of SO 2 reductions have taken place at 22 plants in the U.S. by 2012 as a result of 6 settlement agreements. 68 More than half of these plants are in states affected by this proposal. This information shows that few if any SO 2 reduct ions are available from other source categories and thus, along with other information available to EPA, supports EPA’s proposal not to include non
- EGU SO 2 reduction requirements for addressing PM2.5 transport for the proposed rule. EPA seeks comment on whether non
- EGU emissions reductions should be required and on the specific control measures that would serve as the basis for those reductions.

68 U.S. EPA. Acid Plant NSR Enforcement Priority. Available at http://www.epa.gov/compliance/civil/caa/acidplant

nsr/index.html .316 Because sulfur content of both gasoline and diesel fuel are now subject to very stringent sulfur requirements, EPA believes there are no available on
- road and nonroad engine measures to reduce mobile source SO 2 at levels below $2,000/ton. b. NOX from Non - EGU S ources For NOX , the methodology described previously in section IV.D.2 requires all states linked to PM2 .5 nonattainment and maintenance areas to ensure that emissions do not increase above 2009 levels. This translates into a cost cutoff of $500/ton. In addition, for ozone, EPA determined that a number of states can eliminate their significant contribution and interference with maintenance by installing controls at this same $500/ton cost threshold. For the CAIR, the technical support document 69 evaluating non
- EGU controls contained a discussion of non
EGU category contributions to the overall NOX emission s inventory and a discussion of available controls. This analysis identified source categories for which regional emissions exceeded 1 percent of the overall inventory in the eastern half of the U.S. EPA has updated this analysis
69 Identification and Discussion of S ources of Regional Point Source NO X and SO 2 emissions other than EGUs. EPA/OAQPS and CAMD. January 2004.317

of non
- EGU NOX controls done for the CAIR with a review of the year 2012 inventory. See TSD

– “ Non - EGU Emissions Reductions Cost and Potential .” The highest
- emitting stationary source categories of non
- EGU NOX emissions are: (1) stationary reciprocating internal combustion engi nes (RICE), (2) industrial, commercial, and institutional (ICI) boilers, (3) Portland cement manufacturing, (4) petroleum refining, (5) glass manufacturing, (6) pulp and paper production, and (7) iron and steel production. EPA has not identified additiona l non
- EGU controls that can be achieved at $500/ton or less. For example, available information 70 suggests that costs of various types of NOX controls are greater than this level for non
- EGU sources such as ICI boilers, iron and steel mills, petroleum refi neries 71 , glass manufacturing plants, and asphalt manufacturing plants. For industrial boilers, a recent report prepared by NESCAUM72 suggests NO X control costs are typically well above $500/ton for ICI boilers.
70 Reference: Identification and Evaluation of Candidate Control Measures. Phase II Final Report. LADCO, June. 2006. Appendix B. 71 Reference: Assessment of Control Technology Options For Petroleum Refineries in the Mid
-Atlantic Region. Final Report. MARAMA, January, 2007. p. 2
- 24. 72 Reference: NESCAUM Applicability and Feasibility of NO X , SO2 , and PM Emissions Control Technologies for Indus trial, Commercial, and Institutional (ICI)Boilers. NESCAUM, November 2008. pp. xvii, 3
- 12
- 13.318

In addition, a recent report prepared by LADCO73 indicated NOX control costs are also well above $500/ton for glass manufacturing plants and asphalt manufacturing plants. For the NO X SIP Call, EPA identified a number of categories where costs were less than $2,000/ton (1990 dollars), includin g large ICI boilers with capacities greater than 250 million BTU/hour, cement kilns, and large RICE emitting more than 1 ton NO X per day. For each of these categories regulated under the NO X SIP call, EPA believes there are no available control measures ( especially that could be implemented by 2012 ) at less than the $500/ton. EPA has not identified further controls for stationary nonpoint sources or mobile source NO X measures that have costs less than $500 per ton. E . State Emissions Budgets As describ ed later , EPA used the cost thresholds identified for each covered state in the previous section and applied them to state
- specific data to develop individual state emissions budgets. These budgets facilitate implementation of the requirement that signifi cant contribution and interference with maintenance
73 Reference: Identification and Evaluation of Candidate Control Measures. Phase II Final Report. LADCO, June. 2006. Appendix B.319

be eliminated. A state’s emissions budget is the quantity of emissions that would remain in that state from covered
sources after elimination of that portion of each state’s significant contribution and interference with maintenance that EPA has identified in today’s proposal , before accounting for the inherent variability in power system operations ( see discussion of variability in section IV.F, later ) . The state emissions budget is a mechanism for
converting the quantity of emissions that a state must reduce (i.e., the state’s significant contribution and interference with maintenance) into enforceable control requirements. In other words, it provides a quantity of emissions to use in developing a reme dy (e.g., the remedy should be designed to achieve the budget in an average year). Because the budget represents emissions that would remain without accounting for variability, it also represents the amount of emissions that would remain after significant contribution and interference with maintenance have been addressed, in an average year. In a year when base case emissions would have been higher than average (e.g., because a large nuclear unit was out of service and more fossil
- fuel
- fired generation was needed), the emissions that would remain after significant contribution320

and interference with maintenance had been addressed also would be higher. The variability limits discussed in section IV.F address this issue. Application of variability limits in the remedies is described in section V.D. 1. Defining SO 2 and Annual NO X St ate Emissions Budgets for EGUs For group 1 states required to make deeper emission reductions in 2014, EPA based each state’s 2014 budgets on the same projections from IPM that were used as inputs into the cost curves explained in section IV.D.2.a previously . For SO 2 , the values were taken from an IPM run requiring all SO 2 reductions available at $2,000/ton. To account for potential interactions with NO X reductions, EPA also assume d NOX reductions at $500/ton. For group 2 states (and for the first phase 2012 budgets for sources required to make greater reductions in 2014) , EPA took a different approach. These states are only required to make SO 2 reductions that could be made throu gh (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built by 2012 and (3) the use of low sulfur coal . B ecause those strategies were already being applied in most states321

covered by this rule in 2009 , 74 EPA believes that the act ual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM. This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in IPM. The on ly exception to this rule is if a source was modeled to install a scrubber by 2012 (because of rules requiring that installation and/or because of information that the company had already contracted to install a scrubber). In this case, EPA adjusted emiss ions from the unit to account for the new scrubber. For 2012 NOX budgets, EPA used the same general methodology for all states that was used for the group 2 states for SO 2 . The $500/ton cost threshold, that EPA has determined can be used to calculate the minimum significant contribution from upwind states linked to downwind nonattainment and maintenance areas , almost exclusively represents reductions from turning on SCR units. EPA believes that instead of defining the budgets based on IPM projections o f what will happen when SCR units are turned on, it is better to use real data, therefore EPA has developed budgets based on a combination of historical heat
74 Even though allowance p rices dropped significantly in 2008 after the Court decision, most sources appear to have continued with the same reduction strategies .322

input, historical emission rates and where new SCR units are expected between now and 2012, projec ted emission rates for those new SCR units. The emission budgets developed using the previous methodology are as follows in Table IV.E - 1: Table IV.E - 1 – SO2 and Annual NOX State Emission Budgets for Electric Generating Units before Accounting for

Variabil ity75 (tons)

State SO 2 , 2012 and 2013 SO 2 , 2014

and Later NO X Annual ,

All Years Alabama 161,871 161,871 69,169 Connecticut 3,059 3,059 2,775 Delaware 7,784 7,784 6,206 District of Columbia 337 337 170 Florida 161,739 161,739 120,001 Georgia 233,260 8 5,717 73,801 Illinois 208,957 151,530 56,040 Indiana 400,378 201,412 115,687 Iowa 94,052 86,088 46,068 Kansas 57,275 57,275 51,321 Kentucky 219,549 113,844 74,117 Louisiana 90,477 90,477 43,946 Maryland 39,665 39,665 17,044 Massachusetts 7,902 7,90 2 5,960 Michigan 251,337 155,675 64,932 Minnesota 47,101 47,101 41,322 Missouri 203,689 158,764 57,681 Nebraska 71,598 71,598 43,228 New Jersey 11,291 11,291 11,826 New York 66,542 42,041 23,341 North Carolina 111,485 81,859 51,800 Ohio 464,964 178 ,307 97,313 Pennsylvania 388,612 141,693 113,903 South Carolina 116,483 116,483 33,882 Tennessee 100,007 100,007 28,362

75 The impact of variability on the budgets is discussed in s ection IV.F, later .323 State SO 2 , 2012 and 2013 SO 2 , 2014

and Later NO X Annual ,

All Years Virginia 72,595 40,785 29,581 West Virginia 205,422 119,016 51,990 Wisconsin 96,439 66,683 44,846 Total 3,893, 870 2,500,003 1,376 ,312 For more detail on how the budgets were developed, see the TSD: “ State Budgets, Unit Allocations, and Unit Emissions Rates ”. 2. Defining O zone S eason NO X S tate Emissions Budgets for EGUs Ozone season NOX budgets were developed the same way as the annual NOX budgets were developed (explained in IV.E.1, previously ). Table IV.E - 2 – Ozone - season NOX State Emissions Budgets for Electric Generating Units Before Accounting for Variability (tons)

State NO X Ozone Season , All Years Alabama 29,738 Arkansa s 16,660 Connecticut 1,315 Delaware 2,450 District of Columbia 105 Florida 56,939 Georgia 32,144 Illinois 23,570 Indiana 49,987 Kansas 21,433 Kentucky 30,908 Louisiana 21,220 Maryland 7,232 Michigan 28,253 Mississippi 16,530324 State NO X Ozone Season , All Years New Jersey 5,2 69 New York 11,090 North Carolina 23,539 Ohio 40,661 Oklahoma 37,087 Pennsylvania 48,271 South Carolina 15,222 Tennessee 11,575 Texas 75,574 Virginia 12,608 West Virginia 22,234 Total 641,614 These budgets are based on a 5 month ozone season (May 1 through September 30) . Consistent with the approach taken by the OTAG, the NO X SIP call, and the CAIR, we propose to define the ozone season, for purposes of emissions reduction requirements in this rule, as May through September. We recognize th at this ozone season for regulatory requirements will have differences from the official state specific ozone monitoring season. EPA requests comment on whether the budgets for the final rule should be based on a longer ozone season, such as March through October. F. Emission Reduction Requirements I ncluding Variability In this section, EPA discusses the inherent variability in electric power system operation and presents proposed variability limits for each state. As explained325

below, EPA proposes to cal culate variability limits for each state and to use those variability limits in conjunction with the budgets (which are based on expected average conditions) to provide limited flexibility (within the limits allowed by the variability provisions) to addres s years in which more fossil generation than projected in the average base case year occurs. This section also presents projected emission reduction results. 1. Variability a. Introduction to P ower S ector Variability Historically, power sector emissions h ave varied over time. Factors, such as fuel switching and installing new emissions controls, which can lead to significant decreases in emissions, primarily affect emissions rates rather than generation and change largely as a result of pollution regulati on. Even when emission rates do n o t change from year to year, overall emissions can change because of factors including power demand, timing of maintenance activities, and unexpected shutdowns of units. E xtreme weather conditions, sudden economic shocks , and other unpredictable events can also significantly impact power generation from fossil units. These factors relate directly to heat input,326

generation, and the routine operation of power plants to supply our electricity, and thus affect total emission s. As discussed previously , EPA has identified a specific amount of emissions that must be prohibited by each state to satisfy the requirements of CAA section 110(a)(2)(D)(i)(I). EPA has also developed state budgets based on its projections of state emi ssions in an average year after the elimination of such emissions. However, because of the unavoidable variability in baseline emissions

– - resulting from the inherent variability in power plant operations
-- state - level emissions may vary somewhat after all significant contribution and interference with maintenance that EPA has identified in today’s proposal are eliminated. This occurs even when the emission rates of the units within the state do n o t change . For this reason, EPA has determined that it i s appropriate to develop variability limits for each state budget. These limits are used to identify the range of emissions that EPA believes may occur in each state following the elimination of all significant contribution and interference with maintenan ce. For the proposed rule, EPA proposes to factor this variability explicitly in its consideration of how to control emissions. The Agency believes that because327

baseline emissions are variable, emissions after the elimination of all significant contribu tion are also variable and thus it is appropriate to take this variability into account. As discussed in detail in section V, EPA proposes and considers specific regulatory remedies that are designed to meet the emissions budget in an average year. Becau se base case emissions may vary from projections, EPA believes these same remedies may incorporate provisions that account for variability. This variability, however, must be limited to provide downwind states with assurance that necessary reductions will be made in upwind states. This section describes how EPA calculated variability limits for each state to achieve this goal. Remedies (i.e., regulatory approaches for achieving emissions reductions) can range from emission rate
-based “direct control” opti ons to options which allow for interstate trading. EPA believes that inherent variability in power system operations affects each state’s baseline emissions and thus also affects a state’s emissions after elimination of all significant contribution and in terference with maintenance. Thus, emissions may vary somewhat after implementation of the remedies under consideration. Under an emission rate
-based approach,328

emission rate limits could be developed that would meet the budget assuming a given pattern of operation for the affected units. If some of the units with higher emission rates actually operated more than projected, the state's actual emissions would be higher. In an interstate trading program, budgets could be developed that each state would be projected to meet in an average year. In some years, however, generation from units in one state may increase (with a corresponding increase in emissions), but because variability in a larger region is less significant than within a single state, the incr ease in one state would be expected to be offset by decreases in other states. Finally, even in an intrastate
- only trading program, the ability to bank allowances could mean that in one year, emissions would be below the budget, while in another year they would be above. In all these cases, variability limits can be used to retain the flexibilities that the various remedies provide to deal with real
- world variability in the operating system, while still providing downwind states reasonable certainty abou t the level of upwind emissions. EPA also notes that explicit consideration of variability in the emissions resulting from a remedy is consistent with removing a state’s “significant329

contribution.” As noted previously, even if the emissions result is va riable from year to year, there is still a similar increment of emissions reductions. For example, because increased emissions in the control case would also correspond to increased emissions in the base case, the increment of emissions representing signi ficant contribution and interference with maintenance would still be removed. Finally, as is explained more below in IV.F.b, the variability limits (as applied, for instance, in the State Budgets/Limited Trading remedy in section V.D.4) are relatively low and thus the total amount of variability allowed is very small compared to total EGU emissions and even smaller when considering all of the emissions within a state . I t is also worth noting that i n the proposed State Budgets/Limited Trading remedy , variab ility is taken into account in such a way that does not allow an overall increase in emissions. Under this remedy, an individual state could emit up to its budget plus variability limit . However, the requirement that all sources hold allowances to cover emissions , and the fact that those allowances are allocated based on state
- specific budgets absent variability, would ensure that total emissions do not increase. This remedy , therefore, ensures not only that3 30

total emissions do not increase above state bu dgets, but also that reductions occur in each and every state. b. How EPA Accounted for I nherent P ower S ector Variability EPA determined 1
- year variability limits and 3
- year rolling average variability limits for each state. First, EPA determined 1
- year variability limits based on historical variability in heat input. Second, EPA determined 3
- year rolling average variability limits using statistical methods to convert the 1
- year variability into 3
- year variability. The approaches EPA used to determine the 1
- year and 3
- year limits are summarized later and described in more detail in the Power Sector Variability TSD . Expected variability over a single year. EPA performed analyses using historical data to demonstrate that there is year
- to - year variability in baseline emissions (even when emission rates for all units are held constant) and to quantify the magnitude of this variability. This year
- to - year variability in emissions is reflected, in combination with other factors, in year
- to year variability in air quality. The focus of the analysis is on quantifying the magnitude of the inherent variability in the baseline emissions (on both a 1
- year and a 3
- year basis). The goals331

of this analysis, therefore, are to determine the typical variability in emissi ons due to changes in generation and excluding variability in emissions due to changes in emission limits, and to set emissions criteria limits that can be used as part of a remedy to ensure that states are eliminating their significant contribution and in terference with maintenance to protect air quality. EPA used statewide average emissions rates projected using IPM to convert historical heat input variability into corresponding emissions variability limits. The approach assessed the variability in stat e - level heat input over a 7
- year time period (2002 through 2008) using the standard deviation and then determined the difference in emissions from the 99 th percent confidence level and the mean. The approach resulted in a maximum allowable variability, in tons, for each state. These values were then divided by the mean emissions values over the 7
- year time period to yield a percentage variability value for each state. See the Power Sector Variability TSD for details. From the state
-by
- state tonnage and p ercentage emission variability values, EPA identified a single set of variability levels (that is, a tonnage and a percentage) based on the historic variability . EPA made the decision to adopt a single, uniform tonnage and percentage level332

pairing to appl y to all states in order to make the application of the variability limits straightforward rather than developing state
-by
- state percentage variability value s. The effect of the pairing is to ensure that each state is allowed adequate variability while mi nimizing the total amount of emissions allowed . Using only a constant percentage for all states that would satisfy the needs of smaller states with a greater range of emissions as a percentage would result in large states being allowed greater variability than needed. Conversely, using a constant tonnage that would satisfy the needs of larger states with greater range of emissions as a tonnage would result in small states being allowed greater variability then needed. To ensure adequate variability limit s even in states with small numbers of units where expected variability would be more pronounced in percentage terms and in large states where expected variability would be more pronounced in absolute tonnage terms , EPA derived variability limits both as a percentage and in terms of absolute emissions (tons) that serves to minimize the total amount of emissions allowed under this combination variability limit approach . For the tonnage and percentage limit criteria, EPA looked at a wide range of percentage and tonnage333

combinations, and chose for further investigation combinations that provided states sufficient variability limits (based on historic variability) and fit the requirement of minimizing the allowed emissions . Plants in states that were close to the variability limits were evaluated more closely to ensure the modeling reflected all controls known to operate. EPA believes that t he chosen limits would not be tighter than these states could be expected to meet. This approach (identifying both a to nnage and a percentage) addresses the difficulty that smaller states with fewer units could face if only percentages were used to set the limits. For instance, in a small state with a budget of 5 , 000 tons of SO 2 , an infrequently used unit that on average emitted 500 tons when it operated 10 percent of the time could increase its emissions to 1 , 500 tons by operating 30 percent of the time in a year when there is unusually high demand for that unit. That would result in a 20 percent increase in statewide emissions. In a much larger state, with a budget of 50,000 tons, such a change in operation would only lead to a 1 percent in change in statewide emissions. For both annual NO X and SO 2 , the percentage variability limits are 10 percent of a state’s budget an d the334

corresponding tonnage variability limits are 5,000 and 1,700 tons for NO X and SO 2 , respectively. These are the values that result from the approach described previously, i.e., these variability levels allow the necessary variability for every state based on its historic variability, while minimizing the amount of emissions allowed. EPA assigned each state one of these values

– either the tonnage limit or the percent limit, whichever was greater for that state. For instance, 10 percent of Connecticut’s SO 2 budget is less than 1,700 tons, so Connecticut received a 1
- year 1,700 ton variability limit for its EGU SO 2 emissions. EGU sources in Connecticut could emit up to the state’s SO 2 budget plus the variability limit of an additional 1,700 tons of S O 2 in a year, and still eliminate the state’s significant contribution and interference with maintenance. Proposed 1
- year variability limits for each covered state are shown in the tables in section I V.F.2, later . See the Power Sector Variability TSD for more details on EPA’s variability approach. Expected variability over a 3
- year time period . Because air quality is assessed under the Act annually on a rolling 3
- year time period, EPA believes that it is appropriate to also evaluate the inherent variab ility in335

emissions over similar time periods, and to establish state budgets with variability limits that ensure that the significant contribution and interference with maintenance that EPA has identified in today’s notice be eliminated. While the year
- t o - year variability in emissions could lead to variability in 3
- year rolling averages, inherent variability is lower over a 3
- year time period than over a 1
- year period and thus a state’s 3
- year variability limit will be lower than the state’s 1
- year variab ility limit . Establishing such 3
- year limits thus provides an opportunity to ensure that the variability limits do not allow greater fluctuation in emissions than justified based on historic variability. EPA estimated the variability in a state’s emissio ns over a 3
- year time period based on the expected variability in emissions for a single year. As summarized later and described in the Power Sector Variability TSD , the Agency used statistical methods to estimate the 3
- year variability based on 1
- year
var iability . T he average variability of a multi
- year sample is the average variability of a single year divided by the square root of the number of years in the multi
- year336

sample. 76 Thus, the variability of a 3
- year average is equal to the annual variability divided by the square root of three. EPA used this approach to determine 3
- year variability limits based on the 1
- year limits. For example, the Agency calculated the 3
- year variability that corresponds to a 1
- year variability of 5,000 tons as 5,000 divi ded by the square root of three, or 2,887 tons. Similarly, EPA calculated the 3
- year variability that corresponds to a 1
- year variability of 1,700 tons as 1,700 divided by the square root of three, or 981 tons. EPA decided to use three years instead of s ome other interval in order to be consistent with 3
- year averaging used to assess attainment with the NAAQS , as explained earlier in this section. Proposed 3
- year variability limits for each covered state are shown in the tables in section I V.F.2, later . See the Power Sector Variability TSD for more details on EPA’s variability approach. 2. State Budgets with Variability L imits As explained previously , EPA determined variability limits for each state. EPA then applied t hese variability limits on a state
-b y - state basis to calculate state
- 76 Moore, David S. and George P. McCabe. Introduction to the Practice of Statistics . 2 nd ed. New York: W.H. Freeman and Company, 1993. p.395.337

specific emissions budgets with variability limits. EPA calculated state budgets with both 1
- year and 3
- year variability limits. Table IV.F
- 1 shows proposed variability limits by state on SO 2 emissions for 2014 and later. Table IV.F
- 2 shows proposed variability limits by state on NO X annual emissions for 2014 and later. EPA requests comment on the proposed variability limits. EPA also requests comment on an alternative calculation method for variability. The alternative method would use the results of the proposed method but add a ceiling based on the maximum percentage of variability among covered states as observed in the historic heat input data described previously . For both NO X annual and SO 2 , the percentage limits calculated using this alternative methodology are 25 and 32 percent of a state’s budget, respectively. Under this alternative calculation method, a state’s variability limit would be no lower than 10 percent of its budget and no higher than 25 or 32 perc ent, for NO X and SO 2 , respectively. Because no state varied more than these percentages, EPA believes they could serve as reasonable cap s on variability limits. These limits would address the issue of small states receiving very large variability limits as a fraction of their budgets.338 For instance, although Connecticut’s proposed 1
- year variability limit of 1,700 tons is greater than 10 percent of its SO 2 budget of 3,059 tons (306 tons), it is also greater than 32 percent of the budget (979 tons). There fore, under this alternative calculation method, Connecticut’s 1
- year SO 2 variability limit would be 979 tons (32 percent of the state’s SO 2 budget). Similarly, for annual NO X , while Connecticut’s proposed 1
- year variability limit of 5,000 tons is greater than 10 percent of its NO X annual budget of 2,775 (278 tons), it is greater than 25 percent of the budget (694 tons). Therefore, under this alternative approach, Connecticut’s 1
- year annual NO X variability limit would be 694 tons. Tables IV.F
- 1 through IV.F - 3 show the variability limits under the proposed and alternative calculation methods. See the Power Sector Variability TSD in the docket for this rule for more details. Table IV.F- 1 – Variability Limits on SO2 Annual Emissions for 2014 and Later for Electric Generating Units ( Tons)

State SO 2 Annual Emissions Budget Proposed Alternative

1
- year Limit 3
- year

Average Limit 1
- year

Limit 3
- year

Average Limit Alabama 161,871 16,187 9,346 16,187 9,346 Connecticut 3,059 1,700 981 979 565 Delaware 7,784 1,700 981 1,700 981 District of Columbia 337 1,700 981 108 62 Florida 161,739 16,174 9,338 16,174 9,338 Georgia 85,717 8,572 4,949 8,572 4,949 Illinois 151,530 15,153 8,749 15,153 8,749339

State SO 2 Annual Emissions Budget Proposed Alternative

1
- year Limit 3
- year

Average Limit 1
- year

Limit 3
- year

Average Limit Indiana 201,412 20,141 11,629 20,141 11,629 Iowa 86,088 8,609 4 ,970 8,609 4,970 Kansas 57,275 5,727 3,307 5,727 3,307 Kentucky 113,844 11,384 6,573 11,384 6,573 Louisiana 90,477 9,048 5,224 9,048 5,224 Maryland 39,665 3,967 2,290 3,967 2,290 Massachusetts 7,902 1,700 981 1,700 981 Michigan 155,675 15,568 8,988 1 5,568 8,988 Minnesota 47,101 4,710 2,719 4,710 2,719 Missouri 158,764 15,876 9,166 15,876 9,166 Nebraska 71,598 7,160 4,134 7,160 4,134 New Jersey 11,291 1,700 981 1,700 981 New York 42,041 4,204 2,427 4,204 2,427 North Carolina 81,859 8,186 4,726 8, 186 4,726 Ohio 178,307 17,831 10,295 17,831 10,295 Pennsylvania 141,693 14,169 8,181 14,169 8,181 South Carolina 116,483 11,648 6,725 11,648 6,725 Tennessee 100,007 10,001 5,774 10,001 5,774 Virginia 40,785 4,078 2,355 4,078 2,355 West Virginia 119,0 16 11,902 6,871 11,902 6,871 Wisconsin 66,683 6,668 3,850 6,668 3,850 Total 2,500,003 Proposed 1
- year variability limits are the larger of ( 1) 1 , 7 00 tons or ( 2) 10 percent of the state's budget. 3
- year limits are the 1
- year limits divided by the square root of three. The alternative 1
- year variability limit is 1,700 tons as long as that amount is between 10 and 32 percent of the state's budget. If 1,700 tons is greater than 32 percent of the state's budget, the state's limit is set at 32 percent of its budget. If 1,700 tons is less than 10 percent of the state's budget, the state's limit is set at 10 percent of its budget.

Table IV.F- 2 – Variability Limits on NOX Annual Emissions for 2014 and Later for Electric Generating Units ( Tons)

State NO X Annual Emissions Budget Proposed Alternative

1
- year Limit 3
- year

Average Limit 1
- year

Limit 3
- year

Average Limit Alabama 69,169 6,917 3,993 6,917 3,993 Connecticut 2,775 5,000 2,887 694 401 Delaware 6,206 5,000 2,887 1,552 896 District of Columbia 17 0 5,000 2,887 43 25 Florida 120,001 12,000 6,928 12,000 6,928 Georgia 73,801 7,380 4,261 7,380 4,261 Illinois 56,040 5,604 3,235 5,604 3,235 Indiana 115,687 11,569 6,679 11,569 6,679 Iowa 46,068 5,000 2,887 5,000 2,887340

State NO X Annual Emissions Budget Proposed Alternative

1
- year Limit 3
- year

Average Limit 1
- year

Limit 3
- year

Average Limit Kansas 51,321 5,132 2,963 5,132 2,963 Kentucky 74,117 7,412 4,279 7,412 4,279 Louisiana 43,946 5,000 2,887 5,000 2,887 Maryland 17,044 5,000 2,887 4,261 2,460 Massachusetts 5,960 5,000 2,887 1,490 860 Michigan 64,932 6,493 3,749 6,493 3,749 Minnesota 41,322 5,000 2,887 5,000 2,887 Missouri 57,681 5,768 3,330 5,768 3,330 Nebraska 43,228 5,000 2,887 5,000 2,887 New Jersey 11,826 5,000 2,887 2,957 1,707 New York 23,341 5,000 2,887 5,000 2,887 North Carolina 51,800 5,180 2,991 5,180 2,991 Ohio 97,313 9,731 5,618 9,731 5,618 Penn sylvania 113,903 11,390 6,576 11,390 6,576 South Carolina 33,882 5,000 2,887 5,000 2,887 Tennessee 28,362 5,000 2,887 5,000 2,887 Virginia 29,581 5,000 2,887 5,000 2,887 West Virginia 51,990 5,199 3,002 5,199 3,002 Wisconsin 44,846 5,000 2,887 5,000 2 ,887 Total 1,376,312 Proposed 1
- year variability limits are the larger of (1) 5,000 tons or (2) 10 percent of the state's budget. 3
- year limits are the 1
- year limits divided by the square root of three. The alternative 1
- year variability limit is 5, 000 tons as long as that amount is between 10 and 25 percent of the state's budget. If 5,000 tons is greater than 32 percent of the state's budget, the state's limit is set at 25 percent of its budget. If 5,000 tons is less than 10 percent of the state's budget, the state's limit is set at 10 percent of its budget.
The NOX ozone season variability limits have been calculated based on five months of data corresponding to the May through September ozone season. EPA is proposing to use the same approach to calculate ozone season limits that the Agency used to calculate the proposed SO 2 and NOX annual variability limits described earlier in this section, but adjusted to reflect the ozone season data.341 Using that approach, the resulting ozone season 1
- year
var iability limits are 2,100 tons and 10 percent of a state’s budget. EPA assigned each state one of these values

– either the tonnage limit or the percent age limit, whichever was greater for that state
- using the same approach as for the SO 2 and NOX annual limits described previously . EPA determined the 3
- year variability limits as the 1
- year limits divided by the square root of three, the same approach used for the SO 2 and NOX annual limits . The NOX ozone season limits resulting from this approach are sh own in Table IV.F
- 3. EPA did not explicitly model ozone season variability limits because it was assumed that the NOX annual limits would also serve to limit variability in the ozone season and that additional constraints were unnecessary. However, a comp arison of the data revealed that these variability limits would be lower than the ozone season emissions shown in EPA’s modeling for this proposed rule in seven states, with the difference ranging from less than 100 tons to about 900 tons. Adding these oz one season variability limits would, presumably, change the NO X emissions projections in the IPM modeling, but the differences are expected not to make a noticeable impact in the overall air quality results.342 As with the SO 2 and NOX annual variability limits, EPA also calculated NO X ozone season limits using the alternative calculation method described previously; the alternative method adds a ceiling based on the maximum percentage of variability among covered states as observed in the historic heat input data . For NO X ozone season , the percentage limit ceiling would be 31 percent of a state’s budget. The NO X ozone season limits resulting from this approach are also shown in Table IV.F
- 3. EPA requests comments on the NO X ozone season limits shown in Tabl e IV.F - 3.

Table IV.F- 3 – Variability Limits on NOX Ozone Emissions for 2014 and Later for Electric Generating Units ( Tons)

State NO X Ozone Season Emissions Budget Proposed Alternative

1
- year Limit 3
- year

Average Limit 1
- year

Limit 3
- year

Average Limi t Alabama 29,738 2,974 1,717 2,974 1,717 Arkansas 16,660 2,100 1,212 2,100 1,212 Connecticut 1,315 2,100 1,212 408 235 Delaware 2,450 2,100 1,212 760 438 District of Columbia 105 2,100 1,212 33 19 Florida 56,939 5,694 3,287 5,694 3,287 Georgia 32,14 4 3,214 1,856 3,214 1,856 Illinois 23,570 2,357 1,361 2,357 1,361 Indiana 49,987 4,999 2,886 4,999 2,886 Kansas 21,433 2,143 1,237 2,143 1,237 Kentucky 30,908 3,091 1,784 3,091 1,784 Louisiana 21,220 2,122 1,225 2,122 1,225 Maryland 7,232 2,100 1,212 2,100 1,212 Michigan 28,253 2,825 1,631 2,825 1,631 Mississippi 16,530 2,100 1,212 2,100 1,212 New Jersey 5,269 2,100 1,212 1,633 943 New York 11,090 2,100 1,212 2,100 1,212 North Carolina 23,539 2,354 1,359 2,354 1,359 Ohio 40,661 4,066 2,348 4,066 2,348 Oklahoma 37,087 3,709 2,141 3,709 2,141343

State NO X Ozone Season Emissions Budget Proposed Alternative

1
- year Limit 3
- year

Average Limit 1
- year

Limit 3
- year

Average Limi t Pennsylvania 48,271 4,827 2,787 4,827 2,787 South Carolina 15,222 2,100 1,212 2,100 1,212 Tennessee 11,575 2,100 1,212 2,100 1,212 Texas 75,574 7,557 4,363 7,557 4,363 Virginia 12,608 2,100 1,212 2,100 1 ,212 West Virginia 22,234 2,223 1,284 2,223 1,284 Total 641, 614 Proposed 1
- year variability limits are the larger of (1) 2,100 tons or (2) 10 percent of the state's budget. 3
- year limits are the 1
- year limits divided by the square root of three . The alternative 1
- year variability limit is 2,100 tons as long as that amount is between 10 and 31 percent of the state's budget. If 2,100 tons is greater than 31 percent of the state's budget, the state's limit is set at 31 percent of its budget. If 2 ,100 tons is less than 10 percent of the state's budget, the state's limit is set at 10 percent of its budget. As discussed in section V.D, the proposed FIPs would apply the 1
- year variability limits commencing in 2014 and the 3
- year variability limits commencing in 2016, noting that application of the 3
- year average limits in 2016 would serve to limit each state’s emissions in 2014 and 2015. The Agency also requests comment on whether the remedy in the proposed FIPs should be modified so that the limits would apply starting in 2012 instead of 2014. In addition, the direct control remedy option on which EPA requests comments includes assurance provisions based on these variability limits that would apply starting in 2012. Thus, EPA also explains later wh at variability limits would apply in 2012 and 2013. T he 1
- year variability limits for 2012 and 2013 would be the same as the variability limits344

for 2014 and later in Tables IV.F
- 1, IV.F
- 2, and IV.F
- 3 for all state budgets except for the SO 2 budgets for the 15 states comprising the stringent SO 2 tier (“group 1”), which have different SO 2 budgets in 2012 and 2013 than in 2014 and beyond. If EPA finalizes a remedy that uses the 2012 and 2013 variability limits, EPA would also start applying the 3
- year variabi lity limits in 2014 (for all state budgets except group 1 SO 2 budgets) which would serve to limit each state’s emissions in 2012 and 2013, in the same way that starting the 3
- year limits in 2016 would serve to limit emissions in 2014 and 2015 under the proposed approach. The 3
- year variability limits would be the same as the 3
- year limits for 2014 and later in Tables IV.F
- 1, IV.F
- 2, and IV.F
- 3. In this alternative approach, the 15 SO 2 group 1 states, which have different SO 2 budgets in 2012 and 2013 than in 2014 and beyond, would be subject to different 1
- year variability limits in 2012 and 2013 than in later years. All of the group 1 states have sufficiently large SO 2 budgets in 2012 and 2013 that the tonnage limit of 1,700 tons would not apply and the 1
- year limits would be 10 percent of the state SO 2 budgets. The 2012 and 2013 1
- year345

limits on SO 2 emissions for these 15 states under this alternative approach are shown later in Table IV.F
- 4. Additionally, commencing in 2013, EPA would apply in these 15 states a distinct 2
- year average variability limit on SO 2 emissions for the years 2012 and 2013. Analogous to the 3
- year average in subsequent years, this 2
- year average limit would restrict average variability in 2012 and 2013 more than the 1
- year ave rage alone. Table IV.F
- 4 shows, for this alternative approach, 2
- year variability limits on SO 2 emissions for 2012 and 2013 for the 15 group 1 states. For these states, the 3
- year variability limits for later years would be as shown in Tables IV.F
- 1, IV. F - 2, and IV.F
3. For an alternative approach where variability limits start in 2012 instead of 2014, EPA considered

– instead of two - year average limits on SO 2 emissions in the 15 group 1 states in 2012 and 2013

– applying 3
- year average limits in these st ates starting in 2014. This would be the same method as for all other state budgets under the alternative where variability limits start in 2012. However, because the 15 group 1 states have different SO 2 budgets in 2012 and 2013 than in 2014 and beyond, calculation of the 3
- year average limits to apply in years spanning the two budget levels is less straightforward. EPA analyzed this346

alternative method for the 15 SO 2 group 1 states and compared results to the results using the two
- year average limits in 2012 and 2013 for these states, and determined that the two
- year average approach is reasonable. See the Power Sector Variability TSD for more information.

Table IV.F
- 4 includes 1
- year and two
- year variability limits calculated according to the proposed methodology. The 2
- year limits are the 1
- year limits divided by the square root of two. The table does not include separate columns with variability limits calculated according to the alternative calculation method (described previously ) because for the SO 2 budgets in Table IV.F
- 4 the alternative calculation method would yield identical results to the proposed method. The Power Sector Variability TSD contains more details on the variability limits. Table IV.F- 4 – 2012 –2013 One - and Two -Year Variability Limits on SO2 Emissions for Group 1 States for Electric

Generating Units (Tons)
State SO 2 Annual Emissions Budget 1
- year Limit Two - year Average Limit Georgia 233,260 23,326 16,494 Illinois 208,957 20,896 14,775 Indiana 400,378 40,038 28,311 Iowa 94, 052 9,405 6,651 Kentucky 219,549 21,955 15,524 Michigan 251,337 25,134 17,772 Missouri 203,689 20,369 14,403 New York 66,542 6,654 4,705347

North Carolina 111,485 11,148 7,883 Ohio 464,964 46,496 32,878 Pennsylvania 388,612 38,861 27,479 Tennessee 100 ,007 10,001 7,072 Virginia 72,595 7,259 5,133 West Virginia 205,422 20,542 14,526 Wisconsin 96,439 9,644 6,819 1
- year variability limits calculated by the proposed method are the larger of (1) 1,700 tons or (2) 10 percent of the state's budget. Two
- ye ar limits are the 1
- year limits divided by the square root of two. The alternative 1
- year variability limit is 1,700 tons as long as that amount is between 10 and 32 percent of the state's budget. If 1,700 tons is greater than 32 percent of the state's bu dget, the state's limit is set at 32 percent of its budget. If 1,700 tons is less than 10 percent of the state's budget, the state's limit is set at 10 percent of its budget. The alternative calculation method would yield identical limits to the limits determined using the proposed method for the budgets in Table IV.F - 4. 3. Summary of Emissions Reductions Across All C overed S tates Table IV.F
- 5 presents projected power sector emissions in the base case (i.e., without the proposed Transport Rule or CAIR) c ompared to projected emissions with the proposed Transport Rule in 2012 and 2014 for all covered states. Table IV.F
- 6 presents 2005 historical power sector emissions compared to projected emissions with the Transport Rule in 2012 and 2014. Table IV.F- 5 – Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States with the Transport Rule Compared to Base Case without Transport Rule or CAIR (Million Tons)
2012 Base Case Emissions 2012

Transport Rule Emissions 2012

Emissions Redu ctions 2014

Base Case Emissions 2014

Transport Rule Emissions 2014

Emissions Reductions348

SO 2 8.4 3.4 5.0 7.2 2.6 4.6 Annual NO X 2.0 1.3 0.7 2.0 1.3 0.7 Ozone Season NO X 0.7 0.6 0.1 0.7 0.6 0.1 Note: Emissions differ from emissions budgets due to banking
Table IV.F- 6 – Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States with the Transport Rule Compared to 2005 Actual Emissions (Million Tons) 2005 Actual Emissions 2012

Transport Rule Emissions 2012

Emissions Reduction s from 2005 2014

Transport Rule Emissions 2014

Emissions Reductions from 2005 SO 2 8.9 3.4 5.5 2.6 6.3 Annual NO X 2.7 1.3 1.4 1.3 1.4 Ozone Season NO X 0.9 0.6 0.3 0.6 0.3 Note: Emissions differ from emissions budgets due to banking
G . How the P roposed Approach is C onsistent with Judicial Opinions I nterpreting S ection 110(a)(2)(D)(i)(I) of the Clean Air Act The methodology described previously quantifies states’ significant contribution and interference with maintenance in a manner that is consistent with the decisions of the D.C. Circuit. As discussed in s ection III previously , the D.C. Circuit has issued two significant decisions addressing the requirements of 110(a)(2)(D)(i)(I). The first opinion largely upheld the NOX SIP Call, Michigan v. EPA , 2 13 F.3d 663 (D.C. Cir.349

2000), and the second found significant flaws in the CAIR, North Carolina v. EPA , 531 F.3d. 896 (D.C. Cir. 2008). In both cases, the Court considered aspects of the methodology used by EPA to identify emissions that, pursuant to sec tion 110(a)(2)(D)(i)(I), must be eliminated due to their impact on air quality in downwind states. EPA believes that the methodology used in this proposed T ransport Rule is consistent with both opinions and rectifies the flaws the North Carolina Court ide ntified with the methodology used in CAIR. The methodology used for this proposed rule relies on state
- specific data to analyze each individual state’s significant contribution, uses air quality considerations in addition to cost considerations to identif y each state’s significant contribution, and gives independent meaning to the “interference with maintenance” prong. This methodology is then applied in a reasonable manner consistent with the relevant judicial opinions. In North Carolina , the Court held that EPA’s approach to evaluating significant contribution was inadequate because, by evaluating only whether emissions reductions were highly cost effective “at the regional level assuming a trading program”, it failed to conduct the required state - specif ic analysis of significant contribution. See i d . at 907. EPA, the Court concluded, “never measured the350

‘significant contribution’ from sources within an individual state to downwind nonattainment areas.” Id . The Court did not, however, disturb the air quality based methodology used by EPA to identify the states with contributions large enough to warrant further consideration. For this proposed transport rule, EPA use s a first step similar to that used in the CAIR to identify the states with relatively l arge contributions. However, in contrast to the CAIR, it then use s a state - specific analysis. Instead of identifying a single emission s level that could be achieved by the application of highly cost effective controls in the region, EPA determine s , on a state -by
- state basis what reductions could effectively be achieved by sources in that state. EPA’s new approach does not, as the CAIR methodology did , establish a regional cap on emissions that i s then divided into state budgets that set the emission redu ction requirements for each state. Instead, EPA develop s, for each covered state , emissions budgets based on the reductions achievable at a particular cost per ton in that particular state, taking into account the need to ensure reliability of the electri c generating system . The selected cost/ton levels reflect consideration of both cost factors and air quality factors including the351

estimated impact of upwind states’ emissions on each downwind receptor . In addition, in developing this approach, EPA was gu ided by the Court’s holdings regarding the use of cost to identify significant contribution. Specifically, the Court held in Michigan that EPA could “in selecting the ‘significant’ level of ‘contribution’ under section 110(a)(2)(D)(i)(I), choose a level c orresponding to a certain reduction in cost.” North Carolina , 531 F.3d at 917 (citing Michigan , 213 F.3d at 676
- 77). This holding also supported the Court’s conclusion in Michigan that it was acceptable for EPA to apply a uniform cost
- criterion across st ates. See Michigan , 213 F.3d at 679. In the CAIR
case , the Court rejected EPA’s analysis, not because it relied on cost considerations to identify significant contribution , but because it found that EPA had failed to draw the significant contribution lin e at all . See North Carolina , 531 F.3d at 918 (“. . . here EPA did not draw the [significant contribution] line at all. It simply verified sources could meet the SO 2 caps with controls EPA dubbed ‘highly cost
- effective.’”). The holdings in Michigan rega rding the use of cost and a uniform cost
- crit erion across states were left undisturbed. See, e.g., North Carolina , 531 F.3d at 917 (explaining that in Michigan the352

Court held that “EPA may ‘after [a state’s] reduction of all [it] could . . . cost
- effectively eliminate[],’ consider ‘any remaining contribution insignificant”). In fact, the Court acknowledged that, based on the Michigan holdings, the measurement of a state’s significant contribution need not “directly correlate with each state’s individualiz ed air quality impact on downwind nonattainment relative to other upwind states.” North Carolina , 531 F.3d at 908. For these reasons, EPA determined that it was appropriate in this rulemaking to consider the cost of controls to determine what portion of a state’s contribution is its ‘significant contribution.’ However, EPA also heeded the North Carolina Court’s warning that “EPA’ can’t just pick a cost for a region, and deem ‘significant’ any emissions that sources can eliminate more cheaply.” North Ca rolina , 531 F.3d at 918. Thus, in this rulemaking, EPA depart s from the practice used in the NO X SIP Call and in CAIR of evaluating , based solely on the cost of control required in other regulatory environments, what controls would be considered “highly
- c ost - effective.” Instead, as part of its determination of a reasonable cost per ton for upwind state control, EPA evaluate s the air quality impact of reductions at various cost levels and353

considers the reasonableness of possible cost thresholds as part of a multi
- factor analysis . In addition, the methodology used in this rulemaking gives independent meaning to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I). In North Carolina , the Court concluded that CAIR improperly “gave no independent significance to the ‘interfere with maintenance’ prong of section 110(a)(2)(D)(i)() to separately identify upwind sources interfering with downwind maintenance.” North Carolina , 531 F.3d at 910. EPA rectified this flaw in this rulemaking by separately i dentifying downwind “nonattainment sites” and downwind “maintenance sites.” EPA decided to consider upwind states ’ contribution s not only to sites that EPA projected would be in non attainment, but also to sites that, based on the historic variability of t heir emissions, EPA determined may have difficulty maintaining the relevant standards. The specific mechanism EPA used to implement this approach is described in detail in section IV.C. previously . For annual PM2.5 , this approach identified 16 maintenanc e sites in addition to the 32 nonattainment sites identified in the analysis of nonattainment receptors. For 24
- hour PM2.5 this approach identified 38 maintenance sites in addition to the 92 nonattainment sites identified in the analysis of354

nonattainment receptors. For ozone it identified 16 maintenance sites in addition to the 11 ozone nonattainment sites identified. EPA applied this methodology using available information and data to measure the emissions from states in the eastern United States that si gnificantly contribute to nonattainment or interfere with maintenance in downwind
areas with regard to the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS . Although EPA has not completely quantified the total significant contribution of these states wi th regard to all existing standards , EPA has determined, on a state
- specific basis, that the emissions prohibited in the proposed FIPs are either part of or constitute the state’s significant contribution and interference with maintenance. Thus, eliminati on of these emissions will, at a minimum , make measurable progress towards satisfying the 110(a)(2)(D)(i)(I) prohibition on significant contribution and interference with maintenance. H . Alternative Approaches Evaluated But Not P roposed EPA evaluated a number of alternative approaches to defining significant contribution and interference with maintenance in addition to the approach proposed in this rule. Stakeholders suggested a variety of ideas. EPA considered all suggested approaches.355 EPA evaluated appr oaches including those based solely on air quality, based solely on cost with a uniform cost in all states, based on cost per air quality impact (e.g., $ per ug/m3) , and binning of states based on air quality impact. Detailed descriptions of the alternati ve approaches that EPA evaluated are in a TSD in the docket titled “Alternative Significant Contribution Approaches Evaluated .” EPA is not proposing any of the alternative approaches listed here. However, the proposed approach (described in section IV.D) incorporates some elements from these approaches. V. Proposed Emissions Control Requirements This section describes the proposed emissions control requirements in detail. The section starts with V.A which discusses the pollutants included in the proposal, followed by V.B which discusses the source categories covered. Section V.C discusses the timing of the proposed emissions control requirements. Section V.D describes the proposed approach to implement the emission reduction requirements, starting with a description of the NO X SIP Call and CAIR approaches to implementing reductions and the judicial opinions on those approaches, then describing in detail the proposed “remedy” (State Budgets/Limited Trading) for FIPs356

that would implement the emission s reduc tion s, and explaining the s tructure and key e lements of the p roposed Transport Rule t rading p rogram rules f or State Budgets/Limited Trading. Section V.D also describes two alternative remedies on which EPA requests comment. Section V.E presents projected costs and emissions for each remedy option. Section V.F discusses the transition from the CAIR cap
- and
- trade programs to the proposed Transport Rule programs. Section V.G discusses interactions of the proposed programs with the existing Title IV and NO X SIP Call programs. A. Pollutants included in this proposal In this action, EPA is proposing FIPs to directly regulate upwind emissions of SO 2 and NOX because of their impact on downwind states’ ability to attain and maintain the PM2.5 NAAQS. EPA is also proposing to regulate upwind emissions of NO X because of their impact on 8
- hour ozone attainment and maintenance in downwind states. Our rationale for regulating these precursor pollutants is discussed in section IV.B. In this section, we also explain the regulatory mechanism we are proposing to use to regulate these pollutants and take comment on two alternative options. B. Source Categories357 EPA is proposing to require emissions reductions from the power sector. This section discusses EPA’s rationale f or proposing to control power sector emissions, and our rationale for not proposing to control emissions from other source categories at this time. 1. Propose to Control Power Sector Emissions The proposed Transport Rule FIPs would require EGUs with capac ity greater than 25 MWe in the covered states to reduce emissions of SO 2 , NOX , and ozone season NO X . See section V.D.4., later, for a detailed description of the proposed applicability requirements. 77 Electric generating units are important sources of SO 2 and NOX emissions. I n 201 2 , considering other controls that will be in place, EPA projects that if a Transport Rule is not implemented , EGUs would emit more than 70 percent of the total man
-made SO 2 emissions and about 20 percent of the total man -made NOX emissions in the group of 32 states that would be affected by this rule ( see Table III .A- 1 in section III for lists of states). 78

77 Certain non
- EGUs and smaller EGUs were included in the CAIR NOX ozone season program in some CAIR states. EPA proposes that such units would not be covered by the Transport Rule requirements; see section V.F in this preamble for further discussion of these units. 78 Emissions estimates are based on the 2012 baseline projections described in section IV in this preamble.358 EPA has previously conducted extensive analyses of the cost and emissions impacts of SO 2 and NOX reduction policies on the power sector using the Integrated Planning Model (IPM). Examples include EPA’s IPM analyses of a number of multi
-pollutant bills, including the Clean Air Planning Act ( S.843 in 108th Congress), the Clean Power Act ( S.150 in 109th Congress), the Clear Skies Act of 2005 ( S.131 in 109th Congress), the Clear Skies Act of 2003 (S.485 in 108th Congress), and the Clear Skies Manager's Mark (of S.131). EPA also analyzed several power sector multi
pollutant scenarios in July 2009 at the request of Senator Tom Carper. These analyses are on EPA’s website at: ( www.epa.gov/airmarkets/progsregs/cair/multi.html ). EPA’s IPM analysis for CAIR is another example: ( www.epa.gov/airmarkets/progsregs/epa

- ipm/cair/index.html ). Based on these analyses, EPA believes that there exis t reasonable means for EGUs to make substantial reductions in emissions of SO 2 and NOX . EPA also believes that, at this time, EGUs can reduce SO 2 and NOx emissions more cost
effectively than other source categories ( see section IV.D for discussion of cont rol costs for non
- EGU source categories). For these reasons, EPA has decided to require reductions in SO 2 and NOX emissions from EGUs in the FIPs in this proposed rule. EPA requests comments on these359

proposed FIPs and its proposal to require reductions f rom EGUs. 2. Other Source Categories are not Included In these proposed FIPs, EPA is not proposing to include emission reduction requirements for sources other than EGUs. 79 a. Why EPA Does Not Require Reductions f rom Other Source Categories to Address Tran sport Requirements for PM2.5 In the proposed FIPs to address the section 110(a)(2)(D)(i)(I) requirements with respect to the 1997 and 2006 PM2.5 standards, EPA proposes to regulate only emissions from EGUs. As discussed previously in section IV.D, EPA’s r eview of the costs of EGU and non
- EGU controls resulted in a conclusion that substantial SO 2 and NOX reductions from EGU are available at a cost per ton that is lower than the cost per ton of non
- EGU controls. Other analyses discussed in section IV.D demo nstrated that these EGU reductions are sufficient to eliminate the quantity of emissions identified by EPA as significantly contributing to or interfering with maintenance of the 1997 PM2.5 NAAQS in downwind areas. This same section explains that EGU redu ctions substantially address eliminating the quantity

79 See section IV.D.4 for discussi on of non
- EGUs that were included in CAIR NO X ozone season trading program.360

of emissions identified by EPA as significantly contributing to or interfering with maintenance of the 2006 PM2.5 NAAQS, and this same section explains the need for EPA to further analyze remaining wint er PM2.5 exceedances . This conclusion does not, in any way, address whether a FIP promulgated by EPA or SIPs promulgated by the states should include reductions from non
- EGU sources in order to eliminate significant contribution and interference with main tenance for any other NAAQS, including the 1997 ozone NAAQS and future NAAQS for PM2.5 . b. Why EPA Does Not Propose to Require Reductions From Other Source Categories to Address Transport Requirements for Ozone In the FIPs for this proposed rule, EPA is only proposing to require reductions from EGUs to address emissions from those source categories that significantly contribute to or interfere with maintenance of the 1997 ozone NAAQS. As discussed previously in section IV.D, EPA’s review of the costs of EGU and nonEGU controls resulted in a conclusion that significant NO X emissions reductions from EGU are available at a cost per ton that is lower than the cost per ton of nonEGU NO X controls. The same section also explains the need for EPA to further anal yze whether fully addressing upwind state361

responsibilities to reduce NO X emissions that contribute to downwind nonattainment and maintenance problems requires additional reductions at higher cost per ton , which again would involve analysis of potential EGU and non
- EGU reductions and costs. EPA will be moving forward to complete its assessment of pollution transport for the 1997 ozone NAAQS as soon as possible. For future ozone and PM2.5 NAAQS, EPA intends to quantify the emissions reductions needed t o satisfy the requirements of 110(a)(2)(D)(i)(I)_with respect to those NAAQS. EPA has not made any determinations or assessments regarding whether reductions from source categories other than EGUs will be needed to achieve the necessary reductions in each state. C. Timing of Proposed Emissions Reduction Requirements EPA is proposing an initial phase of reductions in 2012 followed by a second phase in 2014. EPA chose these dates to coordinate with the NAAQS attainment deadlines and to assure that reduction s are made as expeditiously as practicable , as described later in this section. This section also discusses how the compliance deadlines address the Court’s concern about timing. Additionally, this section explains that EPA will consider additional reduc tions to address the NAAQS in the future.362

1. Date for Prohibiting Emissions that Significantly Contribute or Interfere with Maintenance of the PM2.5 NAAQS For all areas designated as nonattainment with respect to the 1997 PM2.5 NAAQS, the SIP deadline for attaining that standard must be as expeditious as practicable but no later than April 2010, with a possible extension to no later than April 2015. Many areas have already come into attainment by the April 2010 deadline due in part to reductions achieved under CAIR. Because the 2010 deadline will have passed before the Transport Rule is finalized, we decided to coordinate the deadline for eliminating significant contribution under this rule with respect to the 1997 PM2.5 NAAQS with the April 2015 deadline that applies to areas that will need an extension of the April 2010 deadline. For all areas designated as nonattainment with respect to the 2006 24
- hour PM2.5 NAAQS, the attainment deadline must be as expeditious as practicable but no later than December 2014 with a possible extension to as late as December 2019. Upwind emissions reductions achieved by the 2014 emissions year will help areas that failed to meet the April 2010 deadline, to meet the April 2015 deadline for the 1997 PM2.5 NAAQS. These r eductions will also help areas meet the December 2014 attainment deadline with respect to363

the 2006 PM2.5 NAAQS. Any areas not meeting that deadline, can request a 5 year extension to December 2019. Further, a deadline of January 1, 2014 also provides adequate and reasonable time for sources to plan for compliance with the Transport Rule and install any necessary controls. EPA believes that this deadline is as expeditious as practicable for the installation of the controls needed for compliance ( see furthe r discussion in section IV.D). 2. Date for Prohibiting Emissions that Significantly Contribute or Interfere with Maintenance of the 1997 ozone NAAQS Ozone nonattainment areas must attain permissible levels of ozone “as expeditiously as practicable,” but no later than the date assigned by EPA in the ozone implementation rule (40 CFR part 51) . The areas designated nonattainment in 2004 with respect to the 1997 8
- hour ozone NAAQS in the eastern United States were assigned maximum attainment dates correspondin g to the end of the 2006, 2009, and 2012 ozone seasons. Many areas have already attained due in part to CAIR, federal mobile source standards, and other local, state and federal measures. Those that have not yet attained the standard have maximum attainment dates ranging from 2010 (these are the 2009364

areas that have been granted a 1
- year extension due to clean data in 2009) to 2018. Areas designated “serious” nonattainment areas have a June 2013 maximum attainment deadline. The proposed Transport Rule’s first phase of reductions in 2012 will help the remaining areas with June 2013 maximum attainment deadlines attain the 1997 8
- hour ozone NAAQS by their deadline. The reductions will also improve air quality in areas with later deadlines . 3. Reductions Required by 2012 to Ensure that Significant Contribution and Interference w ith Maintenance are Eliminated as Expeditiously as Practicable EPA is requiring an initial phase of reductions by 2012. These reductions are necessary to ensure that significant c ontribution and interference with maintenance
are eliminated as expeditiously as practicable. This will in turn assist downwind states to achieve attainment as expeditiously as practicable as required by the CAA. Because the proposed rule, if finalized, w ill replace the CAIR, EPA cannot assume that after this rule is finalized, EGUs would continue to emit at the reduced emission levels achieved by CAIR. Instead, it is the emission reduction requirements in the proposed FIPs that will determine the level o f EGU emissions in the eastern United States. For these reasons, EPA is proposing to365

require an initial phase of reductions by 2012 which would ensure that existing and planned SO 2 and NOX controls operate as anticipated. 4 . How C ompliance Deadlines Addre ss the C ourt’s C oncern About T iming As directed by the C ourt in North Carolina v. EPA , 531 F.3d 896 (D.C. Cir. 2008), and described previously, EPA has established the compliance deadlines in the proposed rule based on the respective NAAQS attainment requ irements and deadlines applicable to the downwind nonattainment and maintenance sites . The 2012 deadline for compliance with the limits on
ozone - season NO X emissions is coordinated with the June 2013 maximum attainment deadline for serious ozone nonattai nment areas (taking into account the need for reductions by 2012 to demonstrate attainment by that date). This deadline also coordinated and the requirement that states attain the NAAQS as expeditiously as practicable. The 2014 deadline for compliance with the limits on annual NO X and annual SO 2 emissions is coordinated with the April 2015 maximum attainment deadline for areas that received the maximum 5
- year extension of the 5
- year attainment deadline for the 1997 PM2.5 NAAQS (taking into account the n eed for reductions by 2014 to demonstrate366

attainment by April 2015). This 2014 compliance deadline is also consistent with December 2014 attainment deadline (5 years from designation, in the absence of an extension) for areas designated nonattainment for the 2006 PM2.5 NAAQS. Areas unable to meet this 2014 deadline may seek a maximum 5
- year extension to 2019. In addition, the 2012 compliance deadline for the first
-phase of annual NO X and annual SO 2 emission reductions will assure the reductions are ach ieved as expeditiously as practicable. EPA established the interim 2012 compliance deadline for annual NO X and annual SO2 reductions because a significant number of reductions can be achieved by 2012. However, given the time needed to design and construc t scrubbers at a large number of facilities, EPA believes the 2014 compliance date is as expeditious as practicable for the full quantity of SO 2 reductions necessary to fully address the significant contribution and interference with maintenance. Requirin g reductions in transported pollution as expeditiously as practicable, as well as within maximum deadlines, helps to promote attainment as expeditiously as practicable. This is consistent with statutory provisions that require states to adopt SIPs that pr ovide for attainment as expeditiously as practicable and within the applicable maximum deadlines.367

5. EPA Will C onsider Additional Reductions in P ollution T ransport to Assist in Meeting Any Revised or New NAAQS a. Ozone As noted, in a January 19, 2010, no tice of proposed rulemaking, EPA proposed to strengthen the NAAQS for ozone. In that notice, EPA proposed levels for the ozone standard to a level within the range of 0.060 to 0.070 parts per million. EPA also proposed in this same notice to establish a distinct cumulative, seasonal “secondary” standard, designed to protect sensitive vegetation and ecosystems, including forests, parks, wildlife refuges and wilderness areas 80

. EPA expects to finalize revised NAAQS for ozone in August 2010. After the NAAQS are finalized, EPA will be able to identify areas that are expected to have difficulty attaining and maintaining that standard, and evaluate and analyze the impact of upwind state emissions on those

80 This proposed cumulative, seasonal standard is expressed as an annual index of the sum of weighted hourly concentrations, cumulated over 12 hours per day (8:00 am to 8:00 pm) dur ing the consecutive 3
-month period within the O 3 season with the maximum index value, set at a level within the range of 7 to 15 ppm
- hours .368

standards. EPA has already begun the technical backgroun d work necessary to allow it to move quickly, once the revised ozone standards are promulgated, with a proposal to address upwind emissions that significantly contribute to nonattainment of or interfere with maintenance of those standards. Because that an alysis will take some time, and because EPA recognizes the urgency of responding to the concerns raised by the Court in North Carolina v. EPA , EPA intends to address the requirements of 110(a)(2)(D)(i)(I) with respect to the revised ozone standards in a subsequent proposal. Addressing the 110(a)(2)(D)(i)(I) requirements for the new NAAQS shortly after promulgation of those NAAQS would help clarify the requirements related to transported emissions before downwind state nonattainment SIPs are due. In doing so, the transport rule would aid downwind states in developing plans for attaining and maintaining the new NAAQS. b. Fine Particles EPA is also on a schedule to review and, if necessary update the PM2.5 NAAQS. This review is scheduled for completion in July 2011. EPA plans to conduct background technical analyses so that EPA will be prepared to move quickly, if necessary, with a transport rule related to any revised PM2.5 NAAQS.369

D. Implementing Emissions Reductions Requirements In this rule, EPA is proposing FIP s to eliminate the significant contribution and interference with maintenance EPA has identified in today’s action . We are proposing one “remedy” option to implement the necessary emission s reduction s and taking comment on two other options . B e fore presenting these options we briefly summarize the appro a ches used in the NOX SIP call and CAIR. 1. Approaches taken in NO X SIP call and CAIR In the NO X SIP call and CAIR, EPA developed emissions trading programs as possible remedies to 110(a)(2)(D)(i) (I) SIP deficiencies. States covered by the rules were given the option of joining the trading programs and EPA determined that, by doing so, they would satisfy the requirements of 110(a)(2)(D)(i)(I) with respect to specific NAAQS. The NO X SIP call provi ded an ozone
- season NO X trading program and addressed the requirements of the ozone NAAQS only. The CAIR provided SO 2 , annual NO X , and ozone
season NO X trading programs, and addressed both the 1997 ozone and the 1997 PM2.5 NAAQS. NOX SIP Call approach . T he NOX SIP call proposed a regional cap and trade program as a way to make cost
effective NO X reductions. Created after years of scientific research and air quality data analyses showed that upwind370

NOX emissions can contribute significantly to ozone nonat tainment in downwind states, the NO X Budget Trading Program (NBP) followed several other major efforts to reduce NO x from large, stationary sources. These initiatives included the Acid Rain Program, OTC NO X Budget Program, New Source Review, New Source Pe rformance Standards, application of Reasonably Available Control Technology to existing sources, and other state efforts. By notice dated October 27, 1998 (63 FR 57356), EPA took final action to require states to prohibit specified amounts of emissions of one of the main precursors of ground
- level ozone, NO X , in order to reduce ozone transport across state boundaries in the eastern half of the United States. EPA found that sources in 23 states emit NO X in amounts that significantly contribute to nonattainment of the 1
- hour ozone NAAQS in downwind states. EPA set forth requirements for each of the affected upwind states to submit SIP revisions prohibiting those amounts of NO X emissions that significantly contribute to downwind air quality problems. EPA es tablished statewide NO X emissions budgets for the affected states. States had the flexibility to adopt the appropriate mix of controls for their state to meet the NO X emissions reductions requirements of the SIP call.371 In the final regulation, EPA offered to administer a multi
- state NO X Budget Trading Program for states affected by the NO X SIP call. The NO X Budget Trading Program was an ozone season (May 1 to September 30) cap and trade program for EGUs and large industrial combustion sources, primarily boilers and turbines. The program used a regionwide cap for ozone season NO X emissions. The cap was the sum of the state emissions budgets established by EPA un der the NO X SIP call regulation to help states meet their SIP obligations. Authorizations to emit, known as allowances, were allocated to affected sources based on state trading budgets. The NO X allowance market enabled sources to trade (buy and sell) allowances throughout the year. Sources could reduce NO X emissions in any manner. Options inc luded adding emissions control technologies, replacing existing controls with more advanced technologies, optimizing existing controls, or switching fuels. At the end of every ozone season, each source surrendered sufficient allowances to cover its ozone season NO X emissions (each allowance rep resents one ton of NOX emissions). This process is called annual reconciliation. If a source did not have enough allowances to cover its emissions, EPA automatically deducted allowances from the following year’s allocation at a 3:1 ratio. If a source had excess allowances because it re
-372

duced emissions beyond required levels, it could sell the unused allowances or bank (save) them for use in a future ozone season. To accurately monitor and report emissions,
sourc es use continuous emission monitoring sys tems (CEMS) or other approved monitoring meth ods under EPA’s stringent monitoring requirements (Title 40 of the Code of Federal Regulations [CFR], Part 75). The NOX SIP call cap and trade program was a way to
ma ke cost
- effective NO X reductions. Under the NO X SIP call, states had the flexibility to determine the mix of controls to meet their emissions reductions requirements. However, the rule provides that if the SIP controls EGUs, then the SIP must establish a budget, or cap, for EGUs. The EPA recommended that each state authorize a trading program for NOX emissions from EGUs. Each of the states required to submit a NO X SIP under the NO X SIP call chose to adopt the cap and trade program regulating large boile rs and turbines. Each state based its cap and trade program on a model rule developed by EPA. Some states essentially adopted the full model rule as is, while other states adopted the model rule with changes to the sections that EPA specifically identifi ed as areas in which states may have some flexibility. The NO X SIP call cap and trade program, modeled closely after the OTC NO X Budget Program373

was phased in starting in 2003 for the OTC states, with the majority of affected states participating as of 200 4. CAIR Approach . In May 2005, EPA promulgated CAIR to address emissions in 28 states and the District of Columbia that it found contribute significantly to nonattainment of the 1997 PM2.5 and 8
- hour ozone NAAQS in downwind states. The EPA required thes e upwind states to revise their SIPs to include control measures to reduce emissions of SO 2 and/or NO X . Reducing upwind precursor emissions helps the downwind PM2.5 and 8
- hour ozone nonattainment areas achieve the NAAQS. Moreover, reducing upwind emissio ns makes it possible for attainment to be achieved in a more equitable, cost - effective manner than if each nonattainment area attempted to achieve the NAAQS by implementing local emissions reductions alone. In CAIR, EPA offered states optional regionwide c ap and trade programs, which were similar to the SO 2 trading program in Title IV of the CAA and the NOx Budget Trading Program in the NO X SIP call. CAIR required implementation of emissions reductions requirements for SO 2 and NOX be implemented in two pha ses. The first phase of NO X reductions started in 2009 (covering 2009
- 2014) and the first phase of SO 2 reductions began in 2010 (covering 2010
- 2014); the second phase of reductions for both NO X and SO 2374

would start in 2015 (covering 2015 and thereafter). The required emissions reductions requirements are based on controls that are known to be highly cost effective for EGUs. CAIR also included model rules for multi
- state cap and trade programs for annual SO 2 and NOX emissions for PM2.5 , and seasonal NO X emissions for ozone, that states could choose to adopt to meet the required emissions reductions in a flexible and cost
- effective manner. The CAIR provided for the NO X SIP call cap and trade program to be replaced by the CAIR ozone season NO X trading program. The U.S. Court of Appeals granted several petitions for review of the CAIR and remanded the rule to EPA. Because the Court decided to remand the rule without vacatur, however, CAIR remains in effect. This proposed rule would replace the CAIR upon fin al promulgation. 2. Judicial Opinions Challenges to both the NO X SIP Call and the CAIR were brought before the U.S. Court of Appeals for the D.C. Circuit. In Michigan v. EPA , 213 F.3d 663, the Court largely upheld the NO X SIP Call. The portion of th is opinion most directly related to the remedy selected by EPA, discusses EPA’s decision to utilize a uniform control strategy. The Court rejected two specific challenges to the requirement that “all covered jurisdictions, regardless375

of amount of contribu tion, reduce their NO X by an amount achievable with ‘highly cost
- effective controls.” Id. at 679. EPA’s approach, Petitioners first alleged, was irrational because it did not take into account differences in individual states’ respective contributions to downwind nonattainment. Both small and large contributors were required to make reductions achievable by the application of highly cost effective controls. The court rejected this challenge finding that this result “flows ineluctably from EPA’s decision to draw the ‘significant contribution’ line on the basis of cost differentials.” Id . Petitioners’ second objection to the use of uniform controls was that it failed to take into account the fact that the location of emissions reductions may affect the impact of those reductions on downwind nonattainment areas. Petitioners argued that because reductions closer to the nonattainment area have a greater benefit, EPA’s use of a highly
- cost - effective standard and region
- wide emissions trading did not guarantee that it would have secured the rule’s health benefits at the lowest cost. See i d . The Court rejected this challenge also, giving deference to EPA’s judgment that non
- uniform regional approaches would not “’provide either a significant improvement in air376

quality or a substantial reduction in cost.’” Id . (quoting 63 FR 57423). Petitioners challenging the CAIR also raised issues related to EPA’s use of an interstate trading program to satisfy the requirements of section 110(a)(2)(D)(i)(I). Petitioners cha llenged both the trading program itself and the state budgets. These budgets were used to determine the number of emission allowances allocated to sources in each state or, if the state chose not to participate in the trading programs, the specific emissi on reduction requirements for that state. The Court concluded , in North Carolina v EPA , 531 F.3d 896, that EPA had not demonstrated that the 110(a)(2)(D)(i)(I) remedy promulgated in CAIR would effectuate the statutory mandate of section 110(a)(2)(D)(i)(I ) and promote the goal of prohibiting contributing sources within one s tate from contributing to nonattainment in another state. In reaching this conclusion, the Court emphasized that EPA had not adequately measured each individual state’s significant
con tribution. See i d . at 908 . (“It is unclear how EPA can assure that the trading programs it has designed in CAIR will achieve section 110(a)(2)(D)(i)(I)’s goals if we do377

not know what each upwind state’s ‘significant contribution’ is to another state.”) The Court also emphasized that section 110(a)(2)(D)(i)(I) “prohibits sources ‘ within the State ’ from ‘contribut[ing] significantly to nonattainment in . .

. any other State . . .’” Id . at 907. (quoting section 110(a)(2)(D)(i)(I) and adding emphasis). Whil e recognizing that it was “possible that CAIR would achieve section 110(a)(2)(D)(i)(I)’s goals” it concluded that “CAIR assures only that the entire region’s significant contribution will be eliminated,” and that “EPA is not exercising its section 110(a)(2 )(D)(i)(I) duty unless it is promulgating a rule that achieves something measurable toward the goal of prohibiting sources ‘within the State’ from contributing to nonattainment or interfering with maintenance ‘in any other State.’” Id . at 907. Furthermor e, since CAIR was designed as a “complete remedy to section 110(a)(2)(D)(i)(I) problems” the C ourt emphasized that “it must actually require elimination of emissions from sources that contribute significantly and interfere with maintenance . ” Id . a t 908. In doing so, however, the Court also acknowledged that it had accepted in Michigan v. EPA , 213 F.3d 663 (D.C. Cir. 2000) EPA’s decision to apply uniform emissions controls and its consideration of cost in the378

definition of significant contribution. See No rth Carolina , 531 F.3d at 908. In developing options to eliminate the emissions identified as constituting all or part of a state’s significant contribution and interference with maintenance, EPA has been mindful of the direction provided by the Court. As discussed in greater detail later , EPA believes that each of the remedy options presented is consistent with the Court’s opinions interpreting the requirements of section 110(a)(2)(D)(i)(I). 3. Remedy Options Overview EPA is proposing one “remedy” option to implement the emission s reduction s requirements and taking comment on two alternatives. This section provides a brief overview of the proposed remedy and the two alternatives. Sections V.D.4, V.D.5, and V.D.6, later, describe the proposed remedy and the alternatives in detail. EPA considered a full range of remedy options in developing this proposal . Among other things, EPA considered variations of direct control options , intrastate cap - and
- trade, interstate cap
- and
- trade, hybrids of these approaches , and simple state emissions caps. S takeholders have suggested a variety of remedy options for EPA’s consideration . A TSD in the docket entitled “ Remedy379

Options Evaluated but not Proposed ” describes options that EPA evaluated but is not propos ing . Based on its consideration of a range of options, EPA is proposing one remedy option and requesting comment on two alternatives. The proposed remedy option, discussed later , is a hybrid approach that combines limited interstate trading with other requirements. The alternative remedies on which EPA requests comment include an intrastate trading option and a direct control option . The proposed and alternative remedy options would regulate SO 2 and NOX emissions from EGUs through FIPs in the covered states to eliminate or address the states’ significant contribution to nonattainment in, or interference with maintenance by, downwind areas with respect to the daily and annual PM2.5 NAAQS and the 8
- hour ozone NAAQS. The remedy option EPA is proposing would use state
s pecific control budgets and allow for intrastate and limited interstate trading of emissions allowances allocated to EGUs . This approach would assure environmental results while providing some limited flexibility to covered sources consistent with the Cou rt decision as described later . The approach would also help ease the transition for implementing agencies and covered sources from CAIR to the Transport Rule. Based on380

consideration of a range of options, EPA believes that the proposed option is the bes t approach, for the reasons discussed in section V .D.4 . The Agency is also presenting two alternative remedies for comment. The first alternative for which EPA requests comment would use state
- specific control budgets and allow intrastate trading of emiss ions allowances allocated to EGUs , but no interstate trading. The second alternative for which EPA requests comment is a direct control program in combination with state
- specific control budgets . As discussed in section IV .E , EPA is proposing new state bu dgets developed on a different basis from the CAIR budgets . The intrastate and interstate trading remedy options would use new allowance allocations, also developed on a different basis from the CAIR FIP allowance allocations . See section IV for the prop osed state budget approach and section V .D.4 for proposed allowance allocation approaches. As discussed in section IV.F, EPA believes that inherent variability in power system operations affects each state’s baseline emissions and thus also affects a state ’s emissions after elimination of all significant contribution and interference with maintenance. Thus, emissions may vary somewhat after implementation of the381

remedies under consideration. This includes the proposed remedy option (State Budgets/Limited Trading), the intrastate trading alternative, and the direct control alternative. Sections V.D.4, V.D.5, and V.D.6 describe variability approaches for the proposed remedy and each of the alternative remedies. EPA also considered only establishing state emissions caps. Such an approach would define what must be done to eliminate all (or in some cases part) of each state’s significant contribution and interference with maintenance, but it would not implement specific requirements to eliminate those emission s. As described in section III.C in this preamble, EPA decided to implement the emission reduction requirements through FIPs. To do so, EPA recognized that it needed to do more than establish simple state emissions caps . For this reason, EPA rejected the simple state emission cap option. As with any FIP that EPA issues, a covered state may submit, for review and approval, a state implementation plan (SIP) that replaces the federal requirements with state requirements that would achieve the required redu ctions. A state’s SIP submission to replace the Transport Rule FIP might propose to use any remedy of the state’s choosing that actually eliminate s the emissions382

that significantly contribute to nonattainment or interfere with maintenance downwind. Secti on VII in this preamble further discusses SIP submissions. 4. State Budgets/Limited Trading Proposed Remedy In this action, EPA is proposing FIPs that would establish state
- specific emission control requirements using state budgets starting in 2012 in 32 states 81 . This remedy option would allow unlimited intrastate trading and limited interstate trading to account for variability in the electricity sector , but also includes assurance provisions to ensure that the necessary emissions reductions occur within each covered state. The a ssurance provisions, described later in this section, would restrict EGU emissions within each state to the state’s budget with the variability limit and would ensure that every state is mak ing reductions to eliminate the portion of significant contribution and interference with maintenance that EPA has identified in today’s action . EPA is proposing to impose

81 The 32 states are: Alabama, Arkansas, Connecticut, District of Columbia, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wi sconsin. As noted in section III, for purposes of this rulemaking, when we discuss “states” we are also including the District of Columbia.383

these assurance provisions starting in 2014. State specific emissions budgets with variability limits would be establishe d as de scribed in section IV in this preamble. These budgets without the variability limits would be used to determine the number of emissions allowances allocated to sources in each state: an EGU source would be required to hold one allowance for every ton of SO 2 and/or NO X emitted during the compliance period. Banking of allowances for use in future years would be allowed under the proposed remedy. For the 2012
- 2013 transition period, EPA is proposing the State Budgets/Limited Trading remedy without a ssurance provisions. EPA is taking comment on all aspects of, as well as alternatives to, this option that address the requirements of 110(a)(2)(D)(i)(I) for prohibiting emissions that significantly contribute to or interfere with maintenance of the NAAQS in downwind states. a. Description of the P roposal The proposed FIPs would address the elimination of significant contribution and interference with maintenance by 2014. A first phase of reductions would be required by 2012 to assure that significant contribution and interference with maintenance are eliminated as expeditiously as practicable.384 To directly eliminate the portion of each state’s significant contribution and interference with maintenance that EPA has identified in today’s action , the prop osed remedy utilizes the state budgets with variability limits described in section IV. The budgets without variability limits are used to determine the number of allowances is sued to sources in each state. Each affected source must hold , and surrender t o EPA, allowances equal to its emissions during the compliance period. In addition, assurance provisions under the proposed remedy cap each state’s EGU emissions at a state
- specific budget with a variability limit to ensure that every state actually reduc es, within the state, all emissions necessary to eliminate the portion of its significant contribution and interference with maintenance that EPA has identified in today’s proposal . For the 2012
- 2013 transition period, EPA is taking comment on whether the assurance provisions used to limit interstate trading are needed, since the state
- specific budgets are based on known air pollution controls and thus a high level of certainty exists about where reductions will occur. As described later , the proposed FI Ps include penalty provisions that are adequate to ensure that the budget including a variability limit will not be exceeded385

so that each state eliminates the portion of its significant contribution and interference with maintenance that EPA has identified in today’s proposed action . The proposed remedy establishes four interstate trading programs starting in 2012: two for annual SO 2 , one for annual NO X , and one for ozone season NO X . One SO 2 trading program is for sources in states (referred to as the SO 2 group 1) that need to make more aggressive reductions to eliminate the portion of their significant contribution that EPA has identified in today’s proposed action , while the second is for sources in states (referred to as SO 2 group 2) with less stringen t reduction requirements. States within SO 2 group 1 can trade SO 2 allowances only with other states in that group. Similarly, states within SO 2 group 2 can trade SO 2 allowances only with other states in that group. Note that all states covered for annua l NOX may trade with each other, even if they are in different groups for SO 2 . Table IV.D. 5 in section IV, previously , summarizes the respective covered states for the SO 2 group 1, SO 2 group 2, and annual NOX trading programs; Table IV.E
- 2 lists the state s for the ozone season NO X program . New emissions allowances based on the new state budgets without variability would be allocated to386

individual sources , as described later . Four sets of allowances would be allocated, one for each of the four trading prog rams (SO 2 group 1, SO 2 group 2, NO X annual, and NOX ozone season). This allocation methodology neither uses heat input adjusted by fuel factors, nor relies on the allocation of allowances under Title IV of the Act. Sources would be allowed to trade allowa nces. However, the assurance provisions would limit total emissions from each state, restricting the variability of emissions from any particular state to the variability associated with its baseline emissions prior to the elimination of all or part of the state’s significant contribution or interference with maintenance . Allowance banking is permitted. Banking (or saving) allowances for future use in any given year allows sources flexibility in compliance planning. Banking lowers costs and helps reduce market volatility. Banking also acts as an incentive to reduce emissions early and accumulate allowances that can be used for compliance in future periods. Because the early reductions encouraged by the ability to bank allowances would result in the reduction of emissions below allowable levels earlier than required, the environmental and human health benefits of the reductions would accrue sooner.387

b. How the P roposal Would be I mplemented (1) Applicability The requirements in the proposed FIP s would apply to large EGUs. Specifically, a covered source would be any stationary, fossil
- fuel
- fired boiler or stationary, fossil
fuel
- fired combustion turbine serving at any time, since the later of November 15, 1990 or the start
- up of the unit’s combustion dev ice, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. The term “fossil fuel” is defined as including natural gas, petroleum, coal, or any form of fuel derived from such material. This is the same definition that was used in CAIR and would include all material derived from natural gas, petroleum, or coal, regardless of the purpose for which such material is derived. For example, with regard to consumer products that are made of materials derived from natural gas, pet roleum, or coal, are used by consumers and then used as fuel, these materials in the consumer products would qualify as fossil fuel. Certain cogeneration units or solid waste incinerators otherwise covered by this general category of covered units would be exempt from the FIP requirements. These proposed applicability requirements are essentially the same as those in the CAIR model trading rules and CAIR FIPs388

(reflecting the revised cogeneration unit definition promulgated in October 2007 (72 FR 59195; October 19, 2007)), with some technical corrections to the exemptions. Cogeneration unit exemption. In order to meet the proposed definition of “cogeneration unit,” a unit (i.e., a boiler or combustion turbine) must operate as part of a “cogeneration syst em,” which is defined as an integrated group of equipment at a source (including a boiler or combustion turbine, and a steam turbine generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electrici ty through the sequential use of energy. In order to qualify as a cogeneration unit, a unit also must meet a specified efficiency standard, i.e., the useful power plus one
- half of useful thermal energy output of the unit must equal no less than a certain percentage of the total energy input or, in some cases, useful power must be no less than a certain percentage of total energy input. Total energy input includes all energy input except from biomass. These proposed elements of the “cogeneration unit” def inition are very similar to the definition used in CAIR. However, there are two technical differences. First, under the definition used in CAIR to qualify as a “cogeneration unit,” a unit had to meet the efficiency standard every389

year starting with the f irst 12
-months during which the unit produced electricity. In contrast, under the definition proposed here, a unit can qualify as a “cogeneration unit” if it meets the efficiency standard every year starting the later of November 15, 1990 or the start - up of the unit’s combustion chamber. EPA believes this definition of “cogeneration unit” is preferable because it may be problematic to obtain sufficiently detailed information about unit operations for some units (e.g., old units that may have started produ cing electricity many years ago). This approach is also more consistent with the approach taken in the general applicability criteria. EPA requests comment on whether it may also be problematic to obtain sufficiently detailed information about unit effic iency back to November 15, 1990 and whether the efficiency standard should be limited to even more recent years by requiring that the standard be met every year starting the later of a date (e.g., January 1) of a more recent year (e.g., 2000 or 2005) or th e start up of a unit’s combustion chamber. Second, in CAIR, each unit had to meet individually the efficiency standard. In contrast, under the “cogeneration unit” definition proposed here, if the cogeneration system of which a unit is a part meets the ef ficiency standard on a system
- wide basis, then390

the unit is also deemed to meet that efficiency standard. EPA believes this definition is preferable because it addresses cases where one unit in a cogeneration system is operated at a lower efficiency (e.g., as a “swing” unit whose use varies with demand) to allow the rest of the units in the cogeneration system to operate with higher efficiency. If a unit meets the definition of cogeneration unit (including the efficiency standard), then it may qualify for the proposed cogeneration unit exemption depending on whether it meets additional criteria concerning the amount of electricity sales from the unit. In order to qualify for the exemption, a cogeneration unit would need to supply in any calendar year
- – st arting the later of November 15, 1990 or the start
- up of the unit’s combustion chamber
- – no more than one
- third of its potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. EPA request s comment on whether it may be problematic to obtain sufficiently detailed information about the disposition of a unit’s generation (e.g., how much was used on site or by an industrial host and how much was supplied to a utility distribution system for sal e) back to November 15, 1990 and whether the electricity sales limit should be restricted to391

more recent years by requiring that the limit be met every year starting the later of a date (e.g., January 1) of a more recent year (e.g., 2000 or 2005) or the st art - up of a unit’s combustion chamber. Solid waste incineration unit exemption. The proposed FIP s also includes an exemption for solid waste incineration units commencing operation before January 1, 1985, for which the average annual fuel consumption of non fossil fuels during 1985

– 1987 exceeded 80 percent and, during any three consecutive calendar years after 1990, the average annual fuel consumption of non
- fossil fuels exceeds 80 percent , on a Btu basis . With regard to a solid waste incineration unit commencing operation on or after January 1, 1985, EPA proposes that the unit would be exempt if its average annual fuel consumption of non
- fossil fuel for the first 3 calendar years of operation and for any 3 consecutive calendar years , thereafter , does no t exceed 80 percent. This is the same as the solid waste incineration unit exemption used in CAIR. EPA also proposes to make explicit in the FIP s an interpretation that the Agency adopted in applying CAIR, namely that
-- solely for purposes of applying the fossil
fuel use limitation in the solid waste incineration unit exemption
-- the term “fossil fuel” is limited to natural392

gas, petroleum, coal, or any form of fuel derived from such material “for the purpose of creating useful heat.” For example, this means that consumer products made from natural gas, petroleum, or coal are not fossil fuel, for purposes of determining qualification under the limitation on fossil
- fuel use, because the products (e.g., tires) were derived from natural gas, petroleum, or coal in order to meet certain consumer needs (e.g., to meet transportation needs), not in order to create fuel (i.e., material that would be combusted to produce useful heat). Opt - in units . EPA does not propose to include provisions for units that are n ot otherwise covered to opt in to the trading programs in the proposed FIPs, or the alternative FIP options discussed later . For the Acid Rain Program, opt - in provisions were established by statute in section 410 of the Act. These opt
- in provisions have been used, to date, by relatively few units. For CAIR, EPA promulgated opt
- in provisions that became effective only to the extent that a state adopted the provisions in a SIP. While several states did adopt these opt
- in provisions, no units so far have opted in to the CAIR trading programs. EPA believes, therefore, that it would not be useful to include opt
- in provisions in the FIPs in the T ransport Rule, and is not proposing any such provisions.393 Sources equal to or less than 25 MWe and Non
- EGUs . Certa in smaller EGUs and non
- EGU sources that were included in the NO X Budget Trading Program were brought into the CAIR NOX ozone season trading program. For treatment of such sources in the proposed FIPs, see section V. F in this preamble. In the Northeast, a large number of EGUs serving generators with a nameplate capacity equal to or less than 25 MWe contribute NO X emissions to ozone problems on high electric demand days. There is regional interest in lowering the 25 MWe applicability threshold in the ozone season to deal with this issue and in potentially requiring these units to operate with greater controls than a trading program would necessitate. EPA requests comment on lowering the greater - than
- 25 MWe applicability threshold for EGUs during the ozone season, and whether a trading program offers the right approach for addressing NO X emissions from these smaller EGUs. (2) Allocation of Emissions Allowances EPA proposes to distribute, to sources in each state, a number of emissions allowances equal to th e SO 2 , annual NOX , and ozone
- season emissions budgets for that state identified in section IV. E (the state budgets listed in IV. E are the budgets without accounting for variability).394

As discussed later, EPA proposes to set aside 3 percent of each state’s emissions budgets for new unit s . Table s IV.E. - 1 and IV.E. - 2 in section IV. E , referenced previously , show the permanent SO 2 , NOX , and ozone season NO X budgets for each covered state (without accounting for variability). EPA would distribute four discrete types of emissions allowances for four separate cap and trade programs: SO 2 group 1 allowances, SO 2 group 2 allowances, NOX annual allowances, and NO X ozone season allowances. In the SO 2 group 1 and SO 2 group 2 programs, each SO 2 allowance would authorize the emission of one ton of SO 2 annually. In the NO X annual program, each NO X annual allowance would authorize the emission of one ton of NO X annually. In the NO X ozone season program, each NO X ozone season allowance would authorize the emission of one to n of NOX during the regulatory ozone season (May through September for this proposed rule). Note that, as explained in section IV.E , EPA is taking comment on extending the ozone season for this rule. In each of the four trading programs, a covered source
would be required to hold sufficient allowances to cover the emissions from all covered units at the source during the control period. EPA proposes to assess compliance with395

these allowance
- holding requirements at the source (i.e., facility) level. This se ction explains how EPA proposes to allocate to two sets of units in a state, existing units and new units. This section also describes the new unit set asides in each state, allocations to units that are not operating , and the recording of allowance all oc ations in facility accounts. EPA proposes to base allocations to existing units on projected emissions from these units after elimination of
some or all significant contribution and interference with maintenance (i.e., projected emissions after implementat ion of the proposed FIPs), and after deductions for the new unit set asides. Section IV .E describe s how EPA developed the overall state budgets. EPA requests comment on all aspects of the allocation method, such as the overall state budgets, the need to have existing unit and new unit allowance allocations, the proposed allocation methodology for existing units, and the proposed allocation methodology for new units. EPA believe s the proposed approach is consistent at the state budget and unit level with the Court’s direction and also addresses the new unit issue . The proposed methodology for allocating allowances does not consider heat input or fuel adjustment factors . Note that in light of the Court396

decision, EPA also is not proposing any allocation
methodologies that rely on Title IV existing allowances. EPA requests comment on whether there are alternative allocation methods EPA should consider that are consistent with the Court decision. EPA asks that commenters present any such approaches in detai l to enable thorough evaluation and that they provide a legal analysis demonstrating how the approach is consistent with the Court’s opinions and the statutory mandate of section 110(a)(2)(D). Allocations to existing units . Existing units are units, as de scribed in the Applicability section, previously ( see 4.b), that commenced commercial operation prior to January 1, 2009. EPA proposes that, f or 2012, each existing unit in a given state receive s allowances commensurate with the unit’s emissions reflecte d in whichever total emissions amount is lower for the state, 2009 emissions or 2012 base case emissions projections. In either case, the allocation is adjusted downward, if the unit has additional pollution controls projected to be online by 2012. EPA p roposes to use this same method to allocate allowances for each of the four trading programs (SO 2 group 1, SO 2 group 2, NO X annual, and NO X ozone season). This proposed allocation method is different from the allocation method used in the CAIR.397 For states with lower SO 2 budgets in 2014 (SO 2 group 1 states) , each unit's allocation for 2014 and later is determined in proportion to its share of the 2014 state budget , as projected by IPM. This approach is also different from the allocation method in CAIR. Fu rther details on the proposed allocation method for existing units can be found in the “ State Budgets, Unit Allocations, and Unit Emission s Rates ” TSD in the docket for this rule. The proposed FIPs are designed to remove emissions from each upwind state th at significantly contributes to nonattainment or interferes with maintenance downwind. The allocation method is consistent with the proposed approach for determining each upwind state’s significant contribution and interference with maintenance (described in section IV) because the allocations would be based on the projected remaining emissions from each covered source in each upwind state after removal of the state’s significant contribution and interference with maintenance. EPA proposes to allocate to e xisting units one time, before the T ransport Rule cap and trade programs commence ( see discussion of schedule, later ). The allocations generally would be permanent (with the exception of non operating units, discussed later ) as base amounts and would not be updated. (Note that any unused new source set aside398

allowances would be distributed proportionally to existing units in addition to the base amount.) By not updating the allocations, EPA can allocate for several years at once, which supports the devel opment of allowance trading markets. The proposed unit
- level allocations for existing EGUs for Phases I and II are set forth in the “ State Budgets, Unit Allocations, and Unit Emission s Rates ” TSD in the docket for this rule, but EPA proposes to include them in the final rule in an Appendix A to each set of trading program regulations (i.e., the SO 2 group 1, SO 2 group 2, NO X annual, and NO X ozone season trading programs) . Because the TSD shows the proposed allocations, Appendices A in the proposed trading pr ogram regulations do not repeat the allocations and are simply reserved. The only circumstances under which allocations would not be permanent as base amounts would be if the unit in the Appendix A table turned out not to be a covered unit 82 , or if the uni t stops operating for three consecutive years .

82 If a unit was allocated allowances but turned out not to be a covered unit, then the treatment of the allocation depends on when the Administrator determines the unit is not subject to the trading program. For instance, if the allocation has been recorded, but the Administrator has not completed the compliance determination process for the unit, allowances equal to the allocation wou l d be deducted from the unit’s compliance account.399 Allocations to new units . EPA proposes to allocate emissions allowances to new units from new unit set
- asides in each state. EPA proposes, for each of the four trading programs, to define a new unit as : any covered EGU not listed in the table in Appendix A of the trading rule applicable to that program ; or any unit listed in Appendix A that stopped operating for three consecutive years, is no longer allocated allowances as an existing unit, but resumes opera tion . EPA believes it is important to have a small new unit set - aside in each state to make room for new units that will be adding emissions to the state’s significant contribution and interference with maintenance . To create new unit set
- asides, EPA woul d distribute to existing EGUs a quantity of allowances less than the entire state emissions budgets. EPA would hold back, for the new unit set - aside for a state, 3 percent of the state budget. Three percent was established based on the total amount of
new unit emissions projected for all the covered states ( See “ State Budgets, Unit Allocations, and Unit Emission s Rates ” TSD ) . In this way, new units could be allocated some allowances for their emissions that will add to the state’s significant contributio n to downwind nonattainment or interference with maintenance.400 For every control period after the control period in which a new unit commences commercial operation or, in the case of an existing unit that did not operate for three consecutive years, resumes operation , EPA would allocate to the unit from the new unit set
- asides based on the unit’s reported emissions from the previous control period. EPA would not allocate to a new unit for the control period during which the unit commences commercial opera tion because the unit would have no actual emissions data on which to base such an allocation. EPA proposes that, for the first control per iod for which the new unit wants an allowance allocation from the new unit set aside (after the first year of opera tion), the designated representative of the source that includes the new unit would submit to EPA a request for a new unit allocation. For each control period, any allowances remaining in a state’s new unit set
- aside (after allocations are made to new unit s that request ed allowances) would be distributed to the existing units in that state in proportion to the existing unit’s original allocations. This ensures that total allocations to units in the state would equal the state budget.401 For each control peri od, if the size of the new unit set - aside were insufficient to provide allocations for all new units requesting allowances, then allocations to all new units would be proportionally reduced. EPA requests comment on the proposed allocation approach for new units. EPA also requests comment on alternative allocation approaches that would provide allowances to new units for the control period during which the unit commences commercial operation. Size of new unit set asides . EPA proposes new unit set - asides th at are 3 percent of the state emissions budgets. The size of the new unit set
- aside would be 3 percent for the SO 2 group 1, SO 2 group 2, NO X annual, and NO X ozone season trading programs, as appropriate, for each state. EPA based the size of the proposed new unit set
asides on a comparison of projected emissions from new units to projected emissions from existing units for all covered states under the proposed State Budgets/Limited Trading remedy. As noted previously , EPA proposes that after a unit is no t operating for three consecutive years , the allowances that would otherwise have been allocated to that unit would be allocated to the new unit set
- aside for the state in which the retired unit is located. This approach would allow the size of the new un it set
- asides to402

grow over time . Note that in EPA’s analysis to determine the size of the new unit set
- asides, EPA assumed that allocations for non - operating units would be allocated to the new unit set
- asides after a unit had ceased operating for 3 conse cutive years ( see “ State Budgets, Unit Allocations, and Unit Emission s Rates ” TSD ) . EPA requests comment on the size of the new unit set
- asides. Non - operating units . EPA proposes that, once an EGU does not operate (i.e., does not combust any fuel) for 3 consecutive years, the Agency would no longer allocate allowances to the unit. Starting with the seventh year after the first year during which unit is not operating , all allowances that would otherwise have been allocated to the unit for that seventh yea r and every year thereafter would be allocated to the new unit set
- aside for the state in which the non - operating unit is located. This would provide additional allowances for new units that may need them (e.g., for new units that replace non - operating
un its), and reflects the fact that new unit emissions are included i n the state’s budget that eliminates the portion of significant contribution and interference with maintenance that EPA has identified in today’s proposed action (in an average year) .403 EPA proposes to continue allocating allowances to non operating units during the 3 consecutive years of non
operation plus an additional 3
- year period to reduce the incentive for owners to keep units operating simply to avoid losing the allowance allocations f or those units. Other options that EPA considered include continuing to allocate allowances for an unlimited period of time, or immediately discontinuing allocations to such units upon the unit ceasing operation . Continuing allocations to non - operating un its has the benefit of reducing the incentive to keep units in operation that should otherwise be , for instance, permanently retired due to age and inefficiency. EPA believes there will be less incentive to continue running old, inefficient EGUs if at lea st some allowances would still be received after retirement. On the other hand, stopping allocations for non - operating units realigns allowance allocations with the sources that actually need such allowances. Non - operating units obviously are no longer emitting and so do not need allowances. Moreover , additional allowances may be needed for the new unit set
aside to accommodate new units coming on line in the future. Allocating allowances for a specified, but limited, period after the unit ceases operat ing for 3404

consecutive years , as EPA proposes to do, would be a middle ground approach to this issue. EPA requests comment on the proposed approach for allocating allowances to non
- operating units. EPA requests comment on simplifying allocations by not all ocating at all to non - operating units. EPA also requests comment on maintaining perpetual allocations to non - operating units, similar to the treatment of non
- operating units in the Acid Rain Program. Schedule for determining and recording allowances . As discussed previously , proposed allocations for existing units are shown in the “ State Budgets, Unit Allocations, and Unit Emission s Rates ” TSD . EPA propose s to include final allocations for existing units in the Appendix A for each proposed trading program in the final T ransport Rule. EPA proposes to record initial allowances for existing units in facility accounts by September 1, 2011, for the control periods in 2012, 2013, and 2014. EPA proposes to record allowances for existing units by July 1, 2012 an d July 1 of each year thereafter, for the control periods in the third year after the year the allowances are recorded. For example, EPA would record existing unit allowances by June 1, 2012 for control periods in 2015. Recording allowances several years in advance supports the405

development of the allowance trading markets and provides time for covered sources to plan for compliance. As discussed previously , EPA proposes to determine allocations to a new unit based on the unit’s reported emissions the prio r year. Although the last quarter of emissions data for a year must be submitted to EPA in the fourth quarterly emissions report by January 30 of the next year, the emissions data in that report may be revised based on EPA’s review and may not be finalize d until May or June after receipt of that report. Consequently, EPA proposes to determine new unit allocations by July 1 of the year for which the allocation is determined. (Because, for an ozone season ending September 30, emissions data may not be fina lized until the following February or March, EPA proposes to determine new unit allocations by April 1.) For example, EPA would determine a new unit’s allocations for control periods in 2012 by July 1, 2012. EPA proposes to make the new unit allocation determinations available to the public through a notice of data availability. Under the proposal, objections to the notice could be submitted , and EPA would issue a second notice of data availability referencin g any necessary adjustments of the new unit al locations.406 EPA proposes to record allowances for new units by September 1, 2012 and September 1 of each year thereafter, for the control periods in the year tha t the allowances are recorded. (For the units in the NO X ozone season program, the comparable deadline for recordation of new units’ allowances is June 1.) For example, EPA would record new unit allocations by September 1, 2012 for control periods in 2012. EPA requests comment on the proposed schedule for determining and recording emissions allowa nces, especially administratively
-practical ways to record allowances as soon as possible, so facilities have information useful in compliance planning. Alternative allocation methods. The proposed allocation method, described previously , would determine each unit’s allocation consistent with the proposed approach to determine each state’s significant contribution and interference with maintenance. EPA considered two alternative allocation methods. EPA is requesting comment on whether either alternative should be used instead of the proposed allocation method . As discussed in section IV, the state emissions budgets are determined based on EPA’s analysis of significant contribution and interference with maintenance407

in each upwind state. EPA believes tha t it is appropriate to develop individual unit allowances consistent with this approach. In the proposed approach, EPA does this by allocating down to the individual unit level using all of the same assumptions used in developing the proposed budgets. Un der this approach all units are allocated allowances consistent with their projected emissions, this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment. EPA is taking comme nt on two alternative methodologies that still link unit allowances directly to the way state budgets were developed (and thus, significant contribution was defined). In the alternatives, allowances are equally distributed amongst groups of units such tha t for each group of units, the amount of allowances distributed is equivalent to the way that significant contribution was apportioned for the group of units. In the first alternative, all units within a state would be treated as a single group . The all ocation method would distribute allowances equal to a state’s emissions budget without variability to each covered source in the state (in effect, distributing the responsibility for eliminating significant contribution and interference with408

maintenance ) b ased on each source’s proportional share of total state heat input. The state heat input would be as projected for the initial year of the program. In other words, t his alternative method for distributing allowances would have the effect of distribut ing the responsibility for eliminating all or part of a state’s overall significant contribution and interference with maintenance to individual units based on each unit’s share of projected heat input. In the second alternative allocation method, EPA would identify groups of units in each state that are capable of having similar emissions characteristics (e.g., coal units, oil units, natural gas units). EPA would distribute a state’s emissions budget without variability to each group of units in the state ( in effect, distributing the responsibility for eliminating all or part of significant contribution) based on each group’s proportional share of the budget as projected in the initial year of the program. After apportioning a state’s budget to the groups o f units, EPA would distribute allocations to individual sources within each group based on each source’s proportional share of projected heat input. Like the first alternative allocation method described previously , this alternative distributes each state ’s significant contribution and409

interference with maintenance to individual sources in the state. By determining groups and then distributing allocations within the groups based on proportional shares, this method would treat units within the categories e qually (i.e., the method would not penalize a source that had acted early to control). (3) Allowance Management S ystem EPA proposes that the State Budgets/Limited Trading remedy include an allowance management system (AMS) operated essentially the same as the existing allowance management systems that are currently in use for CAIR and the Acid Rain Program under Title IV. Under the proposed State Budgets/Limited Trading remedy, the SO 2 programs and the NOX programs would remain separate trading programs maintained in EPA’s existing AMS. AMS would be used to track T ransport Rule trading program SO 2 and NOX allowances held by covered sources, as well as such allowances held by other entities or individuals. Specifically, AMS would track the allocation o f all SO 2 and NOX allowances, holdings of SO 2 and NOX allowances in compliance accounts (i.e., accounts for individual covered sources) and general accounts (i.e., accounts for other entities such as companies and brokers), deduction of SO 2 and NOX allowan ces for compliance purposes, and transfers of allowances410

between accounts. The primary role of AMS is to provide an efficient, automated means for covered sources to comply, and for EPA to determine whether covered sources are complying, with the emission s rate limitations and other emissions
- related provisions of the cap and trade programs. AMS also allows the public to see whether sources are complying. In addition, AMS provides data to the allowance market, including a record of ownership of allowance s, dates of allowance transfers, buyer and seller information, and the serial numbers of allowances transferred. (4) Monitoring and reporting EPA proposes to require that Transport Rule
- covered sources monitor and report SO 2 and NOX emissions in accordance with 40 CFR part 75. Sources that would be covered by the proposed Transport Rule are already measuring and reporting SO 2 mass emissions year round under CAIR and/or the Title IV Acid Rain Program. Similarly, most sources that would be covered are alrea dy measuring and reporting NO X mass emissions year round under CAIR. CAIR and the Acid Rain Program both require part 75 monitoring. Consistent, complete, and accurate measurement of emissions, as part 75 requires, ensures that, for a given pollutant, o ne ton of reported emissions from one source is411

equivalent to one ton of reported emissions from another source. Thus, each allowance represents one ton of emissions, regardless of the source for which the emissions are measured and reported. This establ ishes the integrity of each allowance, which instills confidence in the underlying market mechanisms that are central to providing sources with flexibility in achieving compliance. EPA proposes to require monitoring of SO 2 and NOX emissions by all existi ng covered sources by January 1, 2012 for states covered for the daily and/or annual PM2.5 NAAQS, and monitoring of NO X emissions by May 1, 2012 for sources covered for the 8
- hour ozone NAAQS, using part 75 certified monitoring methodologies. New sources would have separate deadlines based upon the date of commencement of commercial operation, consistent with CAIR and the Acid Rain Program. Specifically, a new unit must install and certify its monitoring system within 180 days of the commencement of
comme rcial operation. While, under the Acid Rain Program and CAIR, the deadline was the earlier of 90 operating days or 180 calendar days after commencement of commercial operation, EPA intends to propose that part 75 be revised to use only the 180
- day deadlin e. EPA believes that using only the 180
- day deadline would ensure that new units have412

sufficient time to complete installation and certification of monitoring systems without having to request extensions of time and would facilitate compliance by making t he monitoring deadline clearer for owners and operators and easier for EPA to apply. See a discussion on units transitioning from CAIR and units previously not covered by part 75 requirements in section V. F, later . (5) Assurance provisions To ensure th at the proposed FIPs require the elimination of all emissions that EPA has identified that significantly contribute to nonattainment or interfere with maintenance within each individual state, we are proposing to establish assurance provisions, as describe d later , in addition to the requirement that sources hold allowances sufficient to cover their emissions. These assurance provisions limit emissions from each state to an amount equal to that state’s budget with the variability limit for state budgets, di scussed in section IV. As described there in , this variability limit takes into account the inherent variability in baseline EGU emissions and recognizes that state emissions may vary somewhat after all significant contribution is eliminated. This approach also provides sources with flexibility to manage growth and electric reliability requirements, thereby ensuring the413

country’s electric demand will be met while meeting the statutory requirement of eliminating significant contribution. Starting in 2014, EPA is proposing as part of the FIPs to establish limits on the total emissions that may be emitted from EGUs at sources in each state. For any single year, the state’s emissions must not exceed the state budget with the variability limit allowed for any single year for th at state (i.e., the state’s 1
- year variability limit). In addition, the 3
- year rolling average of the state’s emissions must not exceed the state budget with the variability limit allowed on average for any consecutive 3 years for that state (i.e., the state’s 3
- year variability limit). Note that in 2014 and 2015, EPA would apply only the 1
- year variability limit, and not the 3
- year variability limit. Because emissions would be evaluated against the 3
- year variability limit on a 3
- year rolling average basis, the application of the 3
- year variability limit in 2016 would serve to limit emissions in 2014 and 2015. In other words, in addition to covered sources being required to hold allowances sufficient to cover their emissions, the total sum of EGU emissions in a particular state cannot exceed the state budget with the state’s 1
-414

year variability limit in any one year, and the state’s annual average emissions for any 3
- year period can not exceed, on average, the state budget with the state ’s 3
- year variability limit. The fact of the 3
- year variability limit would further assure that emissions are constrained during the two preceding years. For example, a hypothetical state has a budget of 100,000 tons, a 1
- year variability limit of 10,000 tons, and a 3
- year variability limit of 5,800 tons.

 In the first year, collective emissions from covered EGUs in the state are 120,000 tons, 10,000 tons over the budget with 1
- year variability limit of 110,000 tons, triggering the assurance provisions in t hat year.

 In the second year, collective emissions from covered EGUs in the state are 97,500 tons, below the state budget with 1
- year variability limit of 110,000 tons. Assurance provisions are not triggered.

 In the third year, collective emissions from c overed EGUs in the state are 109,000 tons, below the state budget with 1
- year variability limit of 110,000 tons. Assurance provisions are not triggered for the 1
- year variability limit. But after three years, the state emissions are computed against the 3
- year variability415 limit. The 3
- year rolling average (adding the last 3 years of emissions and dividing that by three) computes to 108,833 and determines that the 3
- year variability limit of 105,800 tons is exceeded, even though in any one year, the 1
- yea r variability limit may not have been exceeded.

 In the fourth year, collective emissions from covered EGUs in the state are 99,000 tons, below the state budget with 1
- year variability limit of 110,000 tons. Assurance provisions are not triggered for the 1
- year variability limit. The 3
- year rolling average of the last 3 years is 101,833, which is less than the 3
- year variability limit of 105,800. Assurance provisions are not triggered for the 3
- year variability limit. The variability limits for each state are shown in Table s IV.F - 1 through IV.F
- 3 in section IV. The basis for the variability limit s is also described in section IV .F . Additional details may be found in the “ Power Sector Variability ” TSD in the docket to this rule. To implement this requirement, EPA would first evaluate whether any state’s total EGU emissions in a control period exceeded the state’s budget with 1
- year variability limit. Next, EPA would evaluate whether any state’s total EGU emissions in a control period exceeded416

the state’s budget with the 3
- year variability limit (once the program is in effect for 3 years, and each year thereafter). If any state’s EGU emissions in a control period exceeded either of these limits, then EPA would apply additional criteria to determine which s ource owners in the state would be subject to an allowance surrender requirement. The proposed allowance surrender requirement, that owners surrender allowances under the assurance provisions would be triggered only for owners of units in a state where the total state EGU emissions for a control period exceed the applicable state budget with the variability limit. Moreover, only an owner whose units’ emissions exceed the units’ allocations plus the owner’s share of the state budget with the variability limit would be subject to the allowance surrender requirement. In applying the additional criteria, EPA would evaluate which source owners in the state had emissions exceeding the respective owner’s share of the state budget with the variability limit (regar dless if the source had enough allowances to cover its emissions). An owner’s share would equal the sum of the allocations of its EGUs in the state, plus its proportional share of the amount of the variability limit that, when included with the state budget, was exceeded by the state’s EGU emi ssions during417

the year involved. If the state emissions exceeded both the state budget with the 1
- year and with the 3
- year variability limit, then the 3
- year variability limit would be used in determining the owner’s share of the state budget. On the other hand, if the state’s total EGU emissions for a control period in a given year did not exceed the state budget with the state’s 1
- year variability limit and did not exceed, on a 3
- year rolling average basis, the stat e budget with the state’s 3
- year variability limit, then the additional criteria concerning the emissions of each owner’s sources in the state would not apply. For more details see subsection V.D.4.i , later, and the rule text at the end of this preamble ( §§ 97.425, 97.525, 97.625, and 97.725

– - Compliance with assurance provisions) . As discussed previously, EPA would not allocate emissions allowances to a new unit for the control period during which the unit commences commercial operation. In the case whe re assurance provisions for a state are triggered in the year that a new unit first operates, the owner’s share
- – if calculated as the sum of the allocations of its EGUs plus its proportional share of the state budget with the variability limit

– - would418

n ecessarily be zero because the new unit would have no allocation for that year. Instead, EPA would use a specific surrogate emissions number to calculate the maximum amount the unit could emit in that year before being required to surrender allowances under the assurance provisions . The surrogate emissions number would apply only if the state’s assurance provisions were triggered and only in the first year of the new unit’s operation. The surrogate emissions number would be calculated by multiplying the unit’s allowable emissions rate (in lbs/MWe) by the unit’s maximum hourly load (in MWe/hr) and a default capacity factor specific to the unit type. The default capacity factors would be : 8 4 percent for coal
fired units, 6 6 percent for gas - fired combined cycle units, and 15 percent for combustion turbines in the NO X annual and SO 2 trading programs; and 8 9 percent for coal
- fired units, 72 percent for gas - fired combined cycle units, and 22 percent for combustion turbines in the NO X ozone season trading program . These percentages are based on the 95th percentile capacity factors for these unit types in quarterly data that have been reported to EPA for coal
fired units commencing operation since 2000 and combustion turbines since 2004. EPA believes that this approach would cover a range of operating conditions for new units and419

thus avoid attributing to each new unit a share of the state budget with variability equal to the maximum amount of emissions possible for the unit in its first operating year, in the ca se where the state's assurance provisions were triggered . ( See “ Capacity Factors Analysis for New Units ” TSD in the docket for further information on the proposed default capacity factors for new units). These assurance provisions are above and beyond t he fundamental requirement for each source to hold enough allowances to cover its emissions in the control period. Failure to hold enough allowances to cover emissions is a violation of the CAA, subject to an automatic penalty and discretionary civil penal ties, as described later . EPA believes the likelihood of triggering assurance provisions is low. The State Budgets/Limited Trading programs have a regional cap that limits overall emissions; state - specific budgets that are the basis for allocating emissi ons allowances in each state ; assurance provisions that each state eliminates the excess emissions leading to significant contribution and interference with maintenance that EPA has identified in today’s proposed action ; and additional allowance surrender requirements for not meeting emissions reductions requirements. As discussed in section e, later , the underlying mechanism of cap and trade, even420

without assurance provisions, has succeeded in reducing emissions below allowance levels. The accumulated da ta, history, and experience from these programs underscore that emissions reductions requirements and environmental and public health goals of the programs were met. However, unlike earlier cap and trade programs (e.g., the Acid Rain, CAIR, and NO X Budget Trading Programs), where allocations were made based on the same average emissions rates for classes of units, in this proposed rule EPA specifically designed budgets that were intended to match up with reductions at certain cost levels used to determine the respective state’s significant contribution and interference with maintenance. This means more units are likely to have allocations close to their emissions when the state is eliminating its significant contribution and interference with maintenance and there is likely to be less need for trading in order for sources to comply with the requirement to hold allowances covering emissions . Additionally, EPA has now added assurance provisions to ensure that emissions within a state do not exceed the state budget with the variability limitation. The existence of these assurance provisions will limit incentives to trade and ensure that state emissions will stay below the level of the budget with the variability421

limit. An example of a circumstance that migh t result in emissions approaching the variability limit is an extended nuclear unit outage that causes a company to run its fossil units harder to meet demand. Increased emissions under such a scenario would not result from the ability to trade across sta te boundaries, or because the fossil units were not controlled, but because the units were operated more. In this type of scenario, emissions would also be higher in a rate -based program that did not allow interstate trading. EPA is setting two criteria t o determine if a state has exceeded its budget using the state budget with the 1
- year variability limit on an annual basis, and the state budget with the 3
- year variability limit on a 3
- year rolling average basis. EPA proposes that emissions from an
owner ’s EGUs in excess of the owner’s share of the state budget with the variability limit would not be a violation of the regulation or the CAA . But t he owner would be required to make an allowance surrender of one allowance for each ton emitted over the owne r’s proportional share of the amount by which state emissions exceed the state budget with the variability limit . This allowance surrender requirement is significant, and EPA believes sufficient, to ensure that the state emissions will not exceed the budge ts plus the variability422

limit. The allowance surrender requirement, however, is less severe than the penalties (discussed later ) that apply if a source fails to comply with the requirement to hold an allowance for each ton emitted by EGUs at the source. However, failing to hold sufficient allowances to meet the allowance surrender requirement would be a violation of the regulations and the CAA. EPA requests comment on whether the allowance surrender requirement should be different (either more or less) than one allowance per ton emitted over the owner’s proportional share of the state budget with the variability limit. In addition, EPA requests comment on whether the exceedance of total emissions by an owner’s sources over the owner’s share of the state budget with the variability limit should be a violation of the CAA and thus subject to discretionary penalties . Finally, EPA requests comment on all aspects of the proposed assurance provisions in the proposed FIP s . (6) Penalties All covered sources mus t hold an allowance for each ton of SO 2 or NO x emitted and are subject to penalties if they fail to comply with this allowance
- holding requirement.423 Each source must hold in its compliance account in the AMS enough allowances issued for the respective annua l trading program (SO 2 group 1, SO 2 group 2, or NOx annual programs) to cover the annual emissions of the relevant pollutant from all the EGUs at the source. The source owner must provide, for deduction by the Administrator, one allowance as an offset and one allowance as an excess emissions penalty for each ton of excess emissions. These are automatic penalties

– - they are required, without any further action by EPA (e.g., any additional proceedings), regardless of the reason for the occurrence of the ex cess emissions. In addition, each ton of excess emissions, as well as each day in the averaging period (i.e., a calendar year), is a violation of the CAA, for which the maximum discretionary penalty is $25,000 (inflation
- adjusted to $37,500 for 2009) per violation under CAA Section 113. For the ozone season control program, the same provisions apply as for an annual program, except that the control period (and averaging period) is the ozone season, not a calendar year. Consequently, the relevant allowance s and emissions are for an ozone season. EPA requests comment on the amount of allowances required for the automatic penalties. c. 2012 and 2013 T ransition P eriod424 For the 2012
- 2013 transition period, EPA is proposing the State Budgets/Limited Trading reme dy without the previously
- described assurance provisions (penalty provisions would remai n in effect), but taking comment on whether the assurance provisions should be in force during that period . New state - specific control budgets (developed as described in section IV) and new allowances would be allocated to sources in the T ransport Rule region. These state budgets would reflect the operation of all existing and planned emission control devices. Under EPA’s proposed approach, f or 2012 and 2013, intrasta te and interstate trading, without the assurance provisions, would be allowed. The locations of existing and planned air pollution control retrofits on EGUs are known, and this knowledge provides greater certainty of where reductions will occur and how these reductions should impact air quality in downwind areas. There would not be sufficient time to complete construction of additional control retrofits or entirely new, controlled EGUs before 2014 83
.

83 U.S. Environmental Protection Agency (U.S. EPA). 2002. Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies. Washington, D.C.425 Consequently, EPA believes that there is a high level of certainty that emissions reductions projected for 2012
- 2013 with interstate trading would be achieved within the states where they are projected to occur , making imposition of the assurance provisions during 2012
- 2013 unnecessary. In addition, EPA beli eves that the two alternative options discussed later present greater implementation challenges than this proposed interim remedy for 2012
- 2013. See sections V.D.5 and V.D.6. Except for the absence of the assurance provisions, the remedy for 2012
- 2013 wo uld be the same as the State Budgets/Limited Trading option, including compliance and penalty provisions described previously . The 2012
- 2013 transition period would provide time for sources to migrate to the new rule requirements in 2014, such as prepari ng for the imposition of the assurance provisions and, for some states, tighter SO 2 budgets. EPA is requesting comment on the proposed approach of locking in emissions reductions for 2012 and 2013 by allocating new state - specific budgets based on signific ant contribution and interference with maintenance and ensuring that pollution control devices operate, while allowing for interstate trading in 2012 and 2013 without the assurance provisions. Assurance provisions would provide sources less flexibility an d therefore likely increase compliance426

costs, but would be required starting in 2014. EPA requests comment on the pros and cons of including assurance provisions or other limitations on trading during the 2012
- 2013 period. Section IV.F presents variabili ty limits for the alternative where assurance provisions would apply during 2012 and 2013 ( see Tables IV.F
- 1 through IV.F
4). d. Electric Reliability The State Budgets/Limited Trading remedy is not a risk to electric reliability. The option for sources t o trade across state borders and to emit up to the specified state budget with variability limit gives ISOs (Independent System Operators) the flexibility to manage regional electricity generation so that reliability is maintained. For example, the operat ions of the electricity generation sector under the State Budgets/Limited Trading remedy, as compared to the option allowing only intrastate trading, would be less constrained by state borders and have greater flexibility to handle unexpected events such a s extreme weather or the loss of generating capacity for extended periods of time. e. How Emissions C ap and T rade P rograms H ave Worked Under Title IV, the NOx SIP Call, and CAIR427 Even absent assurance provisions, cap and trade programs have resulted in broa d
-based emissions reductions distributed across the entire covered area, with the reductions coming where emissions were highest and most cost effective. The national SO 2 emissions cap and trade program that EPA implemented under Title IV of the CAA Amendments (the Acid Rain Program) and the regional SO 2 and NOX programs established under CAA section 110(a)(2)(D)(i), in the form of the NO X Budget Trading Program and the three CAIR trading programs, all have several key components in
common:

 Phases and redu ctions
o An emissions cap is established and the programs are phased in, with increasing stringency to lower emissions.

 Allowance allocation
o Authorizations to emit, i.e., allowances, are allocated to affected sources and are limited by each state’s trading budget.

 Allowance trading
o Markets enable sources to trade allowances.

 Flexible compliance
o Sources have the flexibility to choose the most efficient way to comply including adding emission428 control technologies, updating control technologies, optimizing ex isting controls, switching fuels, and buying allowances.

 Annual reconciliation
o At the end of every compliance period, each source must surrender sufficient allowances to cover its emissions. Excess allowances may be sold or banked for future use.

 Penaltie s and enforcement
o There are automatic penalties and potentially discretionary civil penalties for program noncompliance.

 Stringent monitoring and reporting
o Sources must use approved monitoring meth ods under EPA’s stringent monitoring requirements (40 CFR part 75) to monitor and report emissions.

 Data transparency
o The data on key program elements, such as emissions, allocations, and allowance trades, are publicly available on EPA’s web site and in annual progress reports. About 50 government staff operate these cap and trade programs. They have been successful in achieving the emissions reductions goals at reasonable costs with429

virtually 100 percent program compliance. In the following paragraphs, specific results from the programs are described. These results are documented in program progress reports that are available on EPA’s web site ( www.epa.gov/airmarkets/progress/progress

- reports.html ) and in the docket to this rule, as referenced at the end of each program section later . Title IV Acid Rain Progr am -- Emissions Reductions. Since program implementation in 1995, the ARP has reduced SO 2 and NO x emissions from the power sector across the nation. In 2008, the ARP SO 2 program covered 3,572 electric generating units (including 1,055 coal
- fired units, which account for almost 99 percent of total ARP unit SO 2 emissions). Verified data submitted to EPA from 2008 show that:

 SO 2 emissions from power sector sources were 7.6 million tons, which is 52 percent less than 1990 levels and already below the stat utory annual emission cap of 8.95 million tons set for compliance in 2010.

 NO x emissions from power sector sources were 3.0 million tons, which is 51 percent less than 1995 levels and more than double the Title IV NO x program emission reduction objective , but also reflects430 reductions achieved under the NO X Budget and CAIR NO X trading programs . The largest reductions have occurred in the states with the highest power plant emissions. These high emitting areas were upwind of major populations centers and
a reas of environmental and ecological concern. Emissions reductions have led to improvements in air quality with significant benefits to sensitive ecosystems and human health.

 Between the 1989 to 1991 and 2006 to 2008 observation periods, decreases in wet sulfate deposition averaged more than 30 percent for the eastern U.S.

 Acid Neutralizing Capacity (ANC), the ability of water bodies to neutralize acid deposition, increased significantly from 1990 to 2008 in lake and stream long
- term monitoring sites in New England, the Adirondacks, and the Northern Appalachian Plateau.

 Recently updated assessments of U.S. PM2.5 and ozone health
- related benefits estimate that PM2.5 benefits due to ARP implementation in 2010 are valued at $170
- 410 billion annually and ground
- level ozone benefits from ARP implementation in 2010 are valued at $4.1
- $17 billion (estimates are in 2008 dollars). The benefits are primarily from reduced premature mortality.431

See EPA’s docket for this rule and www.epa.gov/airmarkets/progress/ARP_4.html . NOX SIP Call NO X Budget Trading Program
-- Emissions Reductions . From 2003
- 2008, the NBP reduced ozone season NO x emissions throughout the NO X SIP call region each year. Results of the program include:

 In 2008, NBP ozone season NO x emissions totaled 481,420 tons, which is 62 percent below 2000 levels and 9 percent below the 2008 NO X emissions cap . Emissions were also below the caps in 2006 and 2007 .
 The average NO x emission rate for t he 10 highest electric demand days (as measured by megawatt hours of generation) consistently fell every year of the NBP .
 The largest NO x emissions reductions and 8
- hour ozone concentrations reductions took place along the Ohio River Valley, as was pro jected by EPA air quality models of the NO x SIP call.

 Noticeable improvements in ambient concentrations of ozone have been measured across the region.

 Of the 104 areas in the eastern United States designated to be in nonattainment for the 1997 8
- hour
ozon e NAAQS in 2004, 88 areas (85 percent) had ozone air quality better than the level of the 1997 standard432 in 2008. 8
- hour ozone concentrations were 10 percent lower in 2008 than in 2001. This decline is largely due to reductions in NO X emissions required b y the NO X SIP call rule. 84 Over the past several years a series of studies 85 , 86 , 87 have evaluated the NO x SIP call and the link between decreasing NO x emissions and decreasing ozone concentrations. These studies demonstrate that the NO x SIP Call has been ef fective in improving ozone air quality in the eastern U.S. EPA stopped administering the NBP at the conclusion of 2008 control period. States still have the emissions

84 US EPA, Our Nation’s Air Status and Trends through 2008, Office of Air Quality Planning and Standards, EPA
- 454/R

- 09
- 002, Research Triangle Park, NC, pp. 1, 17. 85 Gégo, E., P.S. Porter, A. Gilliland, and S.T. Rao, 2007: Observation
- Based Assessment o f the Impact of Nitrogen Oxides Emissions Reductions on Ozone Air Quality over the Eastern United States. J. Appl. Meteor. Climatol., 46, 994

– 1008. 86 Godowitch, J.M., Hogfrefe, C., & Rao, S.T. 2008. Diagnostic analyses of a regional air quality model: Chan ges in modeled processes affecting ozone and chemical
transport indicators from NO X point source emission reductions. Journal of Geophysical Research, 113, D19303, doi:10.1029/2007JD009537. 87 Godowitch, J.M., Gilliland, A.B., Draxler, R.R., and Rao, S.T. 2008. Modeling assessment of point source NOx emission reductions on ozone air quality in the eastern United States. Atmospheric Environment, 42 (1) 87

– 100.433

reductions requirements under the NO X SIP Call and can use the CAIR NO x ozone season tr ading program to meet these . See EPA’s docket for this rule for more details on the results of the NOx Budget Trading Program, or see www.epa.gov/airmarkets/progress/NBP_4.html . CAIR -- Emissions Reductions . Anticipation of the CAIR regional program in 2008 resulted in an additional 2.8 million tons of SO 2 reductions from 2005 levels in the eastern United States, bringing emissions well under the 2010 Title IV cap. The NO X annual and ozo ne season programs began on January 1 and May 1, 2009, respectively. The SO 2 program began on January 1, 2010. The CAIR cap and trade programs remain in effect, consistent with the Court’s remand, in order to benefit public health and the environment, un til EPA replaces the rule. Allowance trading . Because of the ease with which allowances can be banked, bought and sold, and transferred in the trading programs, robust allowance trading markets have developed over the past fifteen years, along with considerable banking of allowances. Allowance prices and trading activity under the trading programs were reduced in 2008 in response to the Court’s July 2008 decision in North Carolina v. EPA granting petitions for review of CAIR. However, the434

allowance markets remained active. For a recent assessment on allowance markets, see www.epa.gov/airmarkets/resource/docs/marketassessmnt.pdf . Transaction Costs . The cap and trade program results described previously are real, measurable, and very significant. These results demonstrate that cap and trade is a policy tool that can achieve cost
- effective, broad reductions quickly to improve human health and the environment and help states meet their obligations to attain the NAAQS. While s ome have suggested that transa ction costs associated with cap and trade programs
were high or problematic, EPA has found no indication that this is the case. Transaction costs are important because they can diminish the incentive to trade or the amount traded. In fact, few empirical s tudies on transaction costs have been done. EPA has searched the literature and compiled a list of anecdotal discussions on transaction costs, including a study of the ARP’s SO 2 cap and trade program by Ellerman 88 of MIT, published in 2004. Ellerman sugge sts that, while no comprehensive study has been conducted on the subject, “. . .the creation of a standard
88 Ellerman, A. Denny. 2004. "The U.S. SO 2 Cap - and
- Trade Programme," Tradeable Permits: Policy Eval uation, Design and Reform, chapter 3, pp. 71
- 97, OECD.435

unit of account in allowances and the lack of any review requirement for trading has avoided the very large transactions costs that limited . . . ear lier experiments with emissions trading.” Other studies ( see Schennach, 2000 89 ) suggest transaction costs are about one percent of the allowance price. An industry expert, Gary Hart 90 , suggested that a typical fee charged by a brokerage firm is $0.50 for e ach SO 2 allowance. Tietenberg, in his book, Emissions Trading Principles and Practice 91 , explains the role of transaction costs and their impact on trading. Note that Tietenberg and many economists use the word, “permits,” in the same way EPA uses the wo rd, “allowances.” Tietenberg defines transactions costs as “the costs, other than price, incurred in the process of exchanging goods and services. These include the costs of researching

89 Schennach, S.M. 2000. The Economics of Pollution Permit Banking in the Context of Title IV of the 1990 Clean Air Act Amendments. Journal of Environmental Economics and Management 40(3): 189
- 210. 90 Personal communication with Gary Hart, ICAP
- United, June 25, 2007 as quoted in Napolitano, S., J. Schreifels, G. Stevens, M. Witt, M. LaCount, R. Forte, & K. Smith. 2007. “The U.S. Acid Rain Program: Key Insights from the Design, Operation, and Assessmen t of a Cap
- and
- Trade Program.” Electricity Journal. Aug./Sept. 2007, Vol. 20, Issue 7. doi:10.1016/j.tej.2007.07.001. 91 Tietenberg, T.H. 2006. Emissions Trading Principles and Practice. Washington, D.C. Published by Resources for the Future.436

the market, finding buyers or sellers, negotiating and enforcing c ontracts for permit transfers, completing all the regulatory paperwork, and makin g and collecting payments .” 92 He also describes how to lower transaction costs, as follows: “Transaction costs can be lowered by making permit transactions transparent, by the availability of exchanges and knowledgeable brokers, and by the sharing of information on the availability of cost
- effective abatement technologies, while administrative costs can be lowered by continuous emissions monitoring and by software that streamli nes monitoring and reporting.” 93 He goes on to say, “Price transparency (making prices public) can reduce the uncertainty associate with trading and facilitate negotiations about price and quantity. One good example is [the]...public auctions held each sprin g for the Sulfur Allowance Program [ARP].” 94 Tietenberg contrasts EPA’s earlier credit
-based trading programs in the 1970s and 1980s (U.S. Emissions Trading Program (ETP)) with cap and trade programs, such as the Acid Rain Program for SO 2 . He says that while credit
based programs “typically involved a considerable amount of

92 Ibid ., p . 41 93 Ibid ., p. 73 94 Ibid . pp.70
- 71437

regulatory oversight at each step of the process (e.g., certification of credits and approval of each trade),” cap and trade programs use instead a system “that compares actual and aut horized emissions at the end of the year, which can lower transactions costs” compared to a credit program. All the features Tietenberg highlights comprise fundamental aspects of EPA’s cap and trade program design. Program design remains one of the princ iple ways to e nsure lower transaction costs. Over the last 15 years, EPA’s state - of
- the
- art information management system has evolved in parallel with the advancement of technology in order to offer platforms for reporting and receiving data and for publi c access. EPA provides dedicated assistance for sources, states, and regions around the country on program operations and monitoring and reporting, specifically. With limited oversight of transactions, EPA focuses on recording data and information accura tely, including allowance transfers, as well as “true
- up”, where actual emissions are reconciled with allowances held in accounts for compliance. These features of EPA’s program management lead to low transaction costs. EPA is attuned to trying to keep requirements as simple and straightforward as possible, and438

offers substantial and routine training to ensure successful program implementation and regulatory compliance. While some have equated the length of EPA’s trading program rules with higher trans action costs, in fact, the detailed regulatory sections, such as for allocations and the stringent monitoring requirements, form the basis of what actually allows the programs to function with limited oversight, virtually 100 percent compliance, public transparency, and nominal transaction costs. For the ARP, NO X Budget Trading Program, and CAIR trading programs, EPA records all allowance allocations in accounts in an electronic allowance tracking system (currently called the AMS). In addition, EPA reco rds in the AMS all allowance transfers that are submitted by parties for official recordation. These allowance accounts are searchable and visible to the public. The trading program regulations that directly govern allowance trading, i.e., the regulation s governing the establishment of allowance accounts and the submission of allowance transfers , are relatively simple and establish requirements that are easy to meet. See, e.g., 40 CFR 96.151(a) (requiring establishment of source compliance accounts). Al lowances may be held in an allowance account (i.e., banked) for use or trading in any future year in which the trading program439

involved is in effect. See, e.g., 40 CFR 96.155 (allowing banking). Further, allowances may be transferred from one account to another with no restrictions except the requirements that the authorized account representative of the transferor account submit to EPA a simple (generally electronic) allowance transfer form identifying the allowances to be transferred and the account to receive them, and that the allowance s must be currently recorded in the transferor account. See, e.g., 40 CFR 96.160 (requiring submission of specified allowance transfer form) and 96.161(a)(2) (requiring that allowance be in transferor account). This tr ansparency of data and availability of information allows the allowance market to function smoothly . EPA research found no indications that transaction costs have been a problem. From discussions with a leading industry consultant we learned that there is enough competition among the approximately fifteen brokerage houses that any attempt at charging fees in excess of market standards will be bid down through competition. 95 In many instances, clients can negotiate fees even lower than market averages. F inancial exchanges, such as the Chicago
95 Memo from ICF International to EPA Clean Air Markets Division, September 17, 2008. Transaction Costs in Allowance Trading Markets .440

Climate Exchange and New York Mercantile Exchange, added SO 2 and NOX allowances to their list of commodities. Prior to the vacatur of CAIR, transaction costs (broker fee as a percent of allowance price) were estimat ed at less than 0.2 percent for SO 2 , less than 1.8 percent for seasonal NO X , and l ess than 0.5 percent for annual NO X . 96 These transaction costs are low and not expected to affect program outcome. In summary, EPA believes its cap and trade programs functio ned efficiently and did not result in high transaction costs for several reasons. First, i n developing the regulations for the trading programs , EPA strove to make the programs as transparent as possible in order to ensure that relevant data were available to the market , to minimize regulatory oversight of trading activity, and to let the market work unhampered. Strong markets exist that have seen upwards of 273 million SO 2 allowances transferred to date. Educational and professional associations that hold regular conferences for members, regulated entities, government agents, and the public have existed to increase transparency of information and exchange ideas on cap and trade programs for more than a decade. Further, EPA is not aware of any source parti cipating in the trading programs over the past 15 years that expressed
96 Ibid .441

concern about the costs of making allowance transfers. For example, EPA has received no comment in the rulemaking proceedings for the trading programs raising concern about the level o f transactions costs for allowance transfers under these programs, and no party challenged the allowance transfer provisions on appeal of any of the trading program rules. In addition, a ll available information indicates that actual transactions costs ar e very low. For articles written by scholars and economists over the past 15 years on transaction costs, see the docket for this rule. f. How the Remedy in the P roposed FIPs is C onsistent with the Court’s Opinions The proposed remedy discussed in this s ection effectuates the st atutory goal of prohibiting sources within the state from contributing to nonattainment or interfering with maintenance in any other state. See North Carolina , 531 F.3d at 908. T he proposed FIPs eliminate all or the emissions tha t EPA has identified as significantly contributing to downwind nonattainment or interfere nce with maintenance in today’s proposed action by requiring sources to participate in emissions trading programs that allow intrastate trading and limited interstate trading, and that also include provisions to ensure that no state’s emissions442

exceed that state’s budget with variability limit. These assurance provisions, combined with the requirement that all sources hold emissions allowances sufficient to cover their emissions, effectuate the requirement that emissions reductions occur “within the State.” A state’s “significant contribution” is the portion of emissions that must be eliminated 97 . State budgets represent EPA’s estimate of the remaining emissions after elimination of significant contribution, but in actuality the amount of remaining emissions may vary. As explained in greater detail previously, both the budgets and the assurance provisions recognize the inherent variability in state EGU emissions. EPA recognizes that shifts in generation due to changing weather patterns, demand growth, or disruptions in electricity supply from other units, all can affect the amount of generation needed in a specific state and thus baseline EGU emissions from that state. Because states’ baseline emissions are variable, their remaining emissions after all significant contribution is eliminated are also variable. In other words , EGU emissions in a state, whose sources have installed all
97 Note that in cases where EPA has not fully identified the quantity of emiss ions that represent significant contribution or interference with maintenance, state budgets define the emissions that remain after the part that has been identified is eliminated.443

controls and taken all measures nec essary to eliminate its significant contribution, could in fact exceed the state budget without variability. For this reason, the assurance provisions limit a state’s emissions to the state’s budget with variability limit. In addition, the requirement that all sources hold emissions allowances (and the fact that the total number of emissions allowances allocated will be equal to the sum of all state budgets without variability) ensures that the use of variability limits both take s into account the inhe rent variability of baseline EGU emissions in individual states (i.e., the variability of total state EGU emissions before the elimination of significant contribution) and recognizes that this variability is not as great in a larger region. The variabili ty of emissions across a larger region is not as large as the variability of emissions in a single state for several reasons. I ncreased EGU emissions in one state in one control period often are offset by reduced EGU emissions in another state within the control region in the same control period. In a larger region that includes multiple states, factors that affect electricity generation, and thus EGU emission s levels, are more likely to vary significantly within the region so that resulting emission s changes in different parts of the region are more444

likely to offset each other. For example, a broad region can encompass states with differing weather patterns, with the result that increased electricity demand and emissions due to weather in one state may b e offset by decreased demand and emissions due to weather in anoth er state. By further example, a broad region can encompass states with differing types of industrial and commercial electricity end
- users, with the result that changes in electricity demand and emissions among the states due to the effect of economic changes on industrial and commercial companies may be offsetting. Similarly, because states in a broad region may vary in their degree of dependence on fossil
- fuel
based electric generation, t he impact of an outage of non
fossil
- fuel
-based generation (e.g., a nuclear plant) in one state may have a very different impact in that state than on other states in the region. Thus, EPA does not believe it is necessary to allow total regional allowance allocations for the states covered by a given trading program to exceed the sum of all state budgets without variability for these states. For these reasons, t he fact that the proposed use of state budgets with the variability limit may allow limited shif ting of emissions between states is not inconsistent with the Court’s holding that emissions reductions must445

occur “within the state.” North Carolina , 531 F.3d at 907. Under the proposed FIPs, no state may emit more than its budget with variability limit and total emissions cannot exceed the sum of all state budgets without variability. This approach takes into account the inherent variability of the baseline emissions without excusing any state from eliminating its significant contribution. It is thus consistent with the statutory mandate of section 110(a)(2)(D)(i)(I) as interpreted by the Court. g. Why EPA is P roposing the State Budgets/Limited Trading Option The FIPs that EPA is proposing use the State Budgets/Limited Trading remedy to eliminate all o f the significant contribution and interference with maintenance that EPA has identified . This remedy
-- which would use state budgets ( see section IV) and allow full trading within each state and limited trading outside of each state

– - would be a cost
- e ffective method for eliminating all or part of each state’s emissions that constitute a significant contribution and interfere with maintenance, would be consistent with the Court’s decision in North Carolina v. EPA , and would address the issues raised by the Court.446 In the first phase (2012 and 2013), the proposed remedy would provide a new interstate trading program that would ensure existing and planned pollution controls operate . Units would be required to run their existing, or already planned, pollut ion control devices when the units are operating. The State Budgets/Limited Trading remedy would use the new state budgets described in section IV and allocate allowances to individual sources using a methodology directly related to the methodology used t o identify emissions that significantly contribute to nonattainment or interfere with maintenance in downwind
areas . EPA believes that because the location of existing and already planned pollution controls for 2012 and 2013 is known, the use of these budgets, even without the added assurance provisions, would assure that the necessary emissions reductions would occur in each state under the trading programs during those years. The impact of the resulting emissions reductions on atmospheric concentrations of particulate matter and other pollution, and subsequent benefits for the environment and human health, would be significant and are described in section s III.B and IX . The proposed remedy would offer the most expeditious approach practicable for compli ance in 2012
- 2013, given the short time available for sources, states,447

and EPA to implement a transition from CAIR. While there is some uncertainty about how quickly units potentially capable of switching fuels would actually be able to implement such fue l switching, the banking provisions of the State Budgets/Limited Trading approach would provide incentives to reduce emissions as quickly and early as possible. The trading provisions would provide flexibility for sources to purchase allowances in the mea ntime, without the risks of unexpected high costs, non
- compliance, or the inability to operate if unable to switch fuels. The remedy would be relatively easy for sources and states to understand and follow as they transition from prior trading programs to a new regime, beginning in 2014, that would include limit s on interstate trading. The second phase would begin in 2014 with tighter state - specific SO 2 caps for states in the more stringent group 1 tier to address significant contribution and interference with maintenance. In addition, assurance provisions limiting interstate trading would become effective in each state. Th is approach in the proposed remedy, which is modeled in several ways after the approaches of the ARP and NBP programs , is likely to le ad to virtually 100 percent compliance. The approach ensures that, as we see economic growth, future air quality is not448

compromised and states can depend on emissions reductions in meeting local air quality goals. The limited interstate trading permitte d in this proposed remedy would address some of the problematic issues identified in the alternative options discussed later , such as, under the intrastate trading option, concerns about the administrative burden and needed resources associated with admini stering 8 2 new trading programs (with 82 new sets of allowances), conducting 82 annual auctions, concentrated allowance market power within individual states, and regional electricity reliability. In particular, the interstate trading component with
assur ance provisions would mean that allowances issued for one state for a trading program could be used in any of the states included in the respective trading program. This feature of the proposed remedy would create a regionwide allowance market, rather tha n single
- state allowance markets where individual owners of sources would be much more likely to have market power ( see discussion later in section V.D.5). Further, the interstate trading component with assurance provisions would provide source owners wit h much more flexibility to ensure electric reliability in the event of future variability in electricity demand (e.g.,449

due to weather or economic changes) or in the availability of specific individual electricity generation facilities. In addition, the p roposed State Budgets/Limited Trading remedy provides reductions at a lower cost than the direct control option described later and is flexible enough to accommodate unit
- specific circumstances. In contrast, the direct control option described later would involve a complex process of determining unit
-by
- unit emissions limits that might need to take account of unit
specific circumstances. Moreover, this option would be roughly $600 million (2006$) more expensive than the pr opos ed remedy in 2012 . See secti on V.E for more details on projected costs and emissions. In summary, EPA believes that interstate trading, although limited by the assurance provisions, would allow source owners to choose among several compliance options to achieve required emissions reductions in the most cost
effective manner, such as installing controls, changing fuels, reducing utilization, buying allowances, or any combination of these actions. Interstate trading with assurance provisions would also allow the electricity sector to c ontinue to operate as an integrated, interstate system able to provide electric reliability. Compared to the alternative options, EPA believes the State450

Budgets/Limited Trading remedy would provide the greatest flexibility to companies complying with the rules and is the approach most likely to achieve the goals and principles outlined in section III.C. The proposed remedy provides intrastate and interstate trading components that simplify implementation for EPA (and, where applicable, states) and sources and results in cost - effective achievement of required emissions reductions. Resource needs for EPA and sources to implement the proposed remedy are expected to be comparable to the resources necessary to implement CAIR. EPA believes the State Budgets/Limited Trading proposed remedy provides more assurance that the emissions levels necessary to address NAAQS nonattainment are not exceeded than most previous regulatory programs such as rate -based direct control programs and even nonattainment plans, none o f which places an absolute cap on emissions. EPA has pointed out, in contrast, that the results from cap and trade programs such as the Acid Rain and NO X Budget Trading programs demonstrate how substantial emissions reductions have been delivered througho ut the respective covered region with high levels of compliance, at low costs, and with significant health and ecological benefits. The proposed State Budgets/Limited Trading remedy provides451

added assurance that emissions reductions now will occur on a sta te -by
- state basis, not just overall at a regional level. These assurance provisions would prohibit states from exceeding their state
- level budgets with variability limits and impose stringent and costly allowance surrender requirements that are known upfr ont to deter exceedances. EPA is confident that the proposed program is both reasonable to implement and stronger than the alternative options. Additionally, this remedy approach and the method EPA proposes for determining significant contribution toge ther provide a workable regulatory structure for not only dealing with the transport problem for the existing NAAQS, but also would be usable in the years ahead when EPA considers further revisions of the NAAQS, notably for ozone and fine particles. EPA r equests comment on the State Budgets/Limited Trading proposed remedy. EPA is also requesting comment on the two options described later in sections V.D.5 and V.D.6. h. Other L imited I nterstate T rading Options Evaluated But Not P roposed EPA considered a range of ways to create an interstate
- trading
- with
- limitations option consistent with the direction provided by the Court. One option considered452

was to put in place simultaneously intrastate trading with direct control requirements and interstate trading with direct control requirements. The challenges associated with developing direct control requirements are discussed in section V.D.6 later . EPA also considered interstate trading with backstop provisions, which were rejected as not workable. EPA
co nsidered a backstop provision that prohibited the units in a state from future participation in the interstate trading program if the state’s emissions in a control period in any year exceeded the state’s budget with variability . In that event, the units would be limited to intrastate trading only in the control period of the next year. EPA is not proposing this approach because data on annual emissions are not final until several months into the next year, making it hard for the units in a state to know early enough whether they would be in the interstate trading program or an intrastate trading program for that next year. This would make compliance planning and implementation of compliance plans extremely difficult and adversely affect allowance markets . In summary, EPA rejected these alternatives as more complicated and perhaps problematic to implement. Instead, EPA is proposing the State Budgets/Limited Trading remedy,453

which is similar in many ways to the approaches implemented in the past that have succeeded in reducing emissions. However, in order to address the Court’s concerns about trading, the proposed remedy includes assurance provisions to ensure that the remedy removes each upwind state’s significant contribution and interference with maintenance. The “ Remedy Options Evaluated but Not Proposed ” TSD in the docket contains greater detail on the deliberations undertaken to evaluate other options, not proposed, for this rulemaking. i. Structure and Key Elements of Proposed Transport Rule Tr ading Program Rules f or State Budgets/Limited Trading This preamble section describes the structure and key elements of the proposed Transport Rule trading program rules for the State Budgets/Limited Trading remedy in the proposed FIPs. Proposed regulatory text that would be added to the Code of Federal Regulations if this option is finalized appears at the end of this notice. EPA explicitly requests comment on the structure and key elements of the program as well as on the proposed regulatory text. In order to make the proposed FIP trading program rules as simple and consistent as possible, EPA designed them so that the proposed rules for each of the trading454

programs (i.e., the Transport Rule NO X Annual trading program, Transport Rule NO X Ozone Seas on trading program, Transport Rule SO 2 Group 1 trading program, and Transport Rule SO 2 Group 2 trading program) would be parallel in structure and contain the same basic elements. For example, the proposed rules for the Transport Rule NO X Annual, NO X Ozon e Season, SO 2 Group 1, and SO 2 Group 2 trading programs would be located, respectively, in subparts AAAAA, BBBBB, CCCCC, and DDDDD of part 97. Moreover, the order of the specific provisions for each trading program would be same, and the provisions would have parallel numbering. The key elements of the proposed Transport Rule trading program rules are discussed later. (1) General Provisions (i) §§ 97.402 and 97.403, 97.502 and 97.503, 97.602 and 97.603, and 97.702 and 97.703
-- Definitions and Abbreviati ons The definitions and measurements, abbreviations, and acronyms would be the same in all four proposed Transport Rule trading programs, except where necessary to reflect the different pollutants (NO X and SO 2 ), control periods (for NOX , annual and ozone s eason), and geographic coverage (for SO 2 , Group 1 and Group 2) involved. Moreover, many of the definitions would be essentially the same as those used in455

prior EPA
- administered trading programs, in some cases with modifications to reflect the specific, pr oposed Transport Rule trading program involved. For example, the definitions of “unit” and “source” would be the same as in prior trading programs. As a further example, the definitions of “allowance transfer deadline,” “owner,” and “operator” would be t he same as in prior trading programs, except for references to Transport Rule NO X Annual allowances, Transport Rule NO X Ozone Season allowances, Transport Rule SO 2 Group 1 allowances, or Transport Rule SO 2 Group 2 allowances or Transport Rule NO X Annual un its and sources, Transport Rule NO X Ozone Season units and source, Transport Rule SO 2 Group 1 units and sources, or Transport Rule SO 2 Group 2 units and sources, as appropriate. As a further example, the term “Allowance Management System” would be used in stead of the term “Allowance Tracking System” but would have essentially the same definition, while referencing the type of allowances appropriate for the proposed Transport Rule trading program involved. As a further example, “continuous emission monitor ing system” is essentially the same as in prior trading programs, except for references to the proposed Transport Rule trading program rules.456 Some definitions would be similar to those used in prior EPA
- administered trading programs but with some substanti ve differences. For example, the definitions of “cogeneration unit” and “fossil
- fuel
- fired,” used in the applicability provisions and discussed in this section of the preamble, would be similar to those in prior trading programs but with changes to minimi ze the need for data concerning individual units or combustion devices for periods before 1990. A few new definitions would be included to reflect unique provisions of the proposed Transport Rule trading programs. For example, the terms, “owner’s assura nce level” and “owner’s share”, would be used in the Transport Rule assurance provisions and defined in the proposed Transport Rule trading program rules. The assurance provisions are discussed previously in section V.D.4.b. (ii) §§ 97.404 and 97.405, 97. 504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705
-- Applicability and Retired Units The applicability provisions would be the same for each of the proposed Transport Rule trading programs, except that the provisions would reflect (through the defin ition of “state”) differences in the specific states whose EGUs are covered by the respective Transport Rule457

trading programs (as discussed in section IV. D of this preamble). In general, the proposed Transport Rule trading programs would cover fossil fuel
- fired boilers and combustion turbines serving an electrical generator with a nameplate capacity exceeding 25 MWe and producing power for sale , with the exception of certain c ogeneration units and solid waste incineration units. The applicability provisio ns are discussed previously in section V.D.4.b. The provisions exempting permanently retired units from most of the requirements of the Transport Rule trading programs would be the same for each of the trading programs. The purpose of the retired units’ e xemption would be to avoid requiring units that are permanently retired to continue to operate and maintain emission monitoring systems, to report quarterly emissions, and to hold allowances, as of the allowance transfer deadline, sufficient to cover their emissions determined in accordance with the monitoring and reporting requirements. Consequently, the retired unit provisions would exempt these units from the rule sections imposing the relevant monitoring, recordkeeping, and reporting requirements and
a llowance
- holding requirements. However, an owner would include each of these permanently retired units that it owns in determining whether and, if so, how many allowances4 58

the owner would be required to surrender in compliance with the assurance provisions . As discussed earlier in this section, while these units would have zero emissions once they are permanently retired, the units could continue to receive allowance allocations for several years thereafter. Consequently, an owner would include these units would be included in determining whether the owner’s share of total emissions of covered units in a state exceeded its share (generally based on the allowances allocated to its units) of the state budget with the variability limit and thus whether the own er would have to surrender allowances under the assurance provisions. The e xemption for a retired unit would begin on the day the unit is permanently retire d. The unit’s designated
r epresentative ( i.e. , the person authorized by the owners and operators t o make submissions and handle other matters) would be required to submit notification to the Administrator within 30 days of the unit’s permanent retirement. The retired unit exemption provisions would not directly address any permit
- related matters conce rning these units. This would be consistent with the general approach under the Transport Rule trading program rules of leaving permitting matters largely to be addressed by the459

existing, applicable state and federal title V permit programs. Permitting i s discussed in section VIII of this preamble. (iii) §§ 97.406, 97.506, 97.606, and 97.706
-- Standard requirements The basic requirements applicable to owners and operators of units and sources covered by the proposed Transport Rule trading programs and p resented as standard requirements would include: designated representative requirements; emissions monitoring, reporting, and recordkeeping requirements; emissions requirements comprising emissions limitations and assurance provisions; permit requirements; additional recordkeeping and reporting requirements; liability provisions; and provisions describing the effect of the Transport Rule trading program requirements on other Act provisions. The paragraphs, in the standard requirements section, that would a ddress designated representative requirements and emissions monitoring, reporting, and recordkeeping requirements would reference the details of these requirements in other sections of the proposed Transport Rule trading program rules. The paragraphs addressing emissions requirements would describe these requirements in detail and reference other460

sections that would set forth the procedures for determining compliance with the emissions limitations and assurance provisions. These paragraphs would also exp lain that: Transport Rule NO X Annual allowances, Transport Rule NOX Ozone Season allowances, Transport Rule SO 2 Group 1 allowances, or Transport Rule SO 2 Group 2 allowances would each authorize emission of one ton of emissions under the applicable Transpor t Rule trading program; such authorizations could be terminated or limited by the Administrator to the extent necessary or appropriate to implement any provision of the Clean Air Act; and such allowances would not constitute a property right. The proposed Transport Rule SO 2 trading programs use new SO 2 allowances and not CAA Title IV allowances, thus the provisions allowing the Administrator to terminate or limit the Transport Rule trading program allowances under this rule would not be contrary to the Cou rt’s North Carolina decision, which addressed the Administrator’s authority to terminate or limit Title IV SO 2 allowances through the CAIR. The remaining paragraphs in the standard requirements section concern permitting, recordkeeping and reporting, liability provisions, and the effect on other CAA provisions. As discussed in section VIII of this preamble, the paragraphs concerning permitting requirements would be461

limited to stating that no title V permit revisions would be necessary to account for allowance allocation, holding, deduction, or transfer and that the minor permit modification procedures could be used to add or change general descriptions in the title V permits of the monitoring and reporting approach used by the units covered by each title V permit. The paragraphs on recordkeeping and reporting would generally require owners and operators to keep on site for 5 years copies (which could be electronic) of certificates of representation, emissions monitoring information (including quarterly emissions data), and submissions and records demonstrating compliance with the proposed Transport Rule trading programs. The paragraphs on liability would state that each covered source and covered unit would be required to meet the Transport Rule trading p rogram requirements, any provision applicable to a source or designated representative would be applicable to the source and unit owners and operators, and any provision applicable to a unit or designated representative would be applicable to the unit owne rs and operators. The paragraph on the effect on other CAA provisions would state that the Transport Rule trading programs do not exempt or exclude owners and operators from462

any other requirements under the CAA, an approved SIP, or a federally enforceable permit. (iv) §§ 96. 4 07 , 97.507, 97.607, and 97.707
-- Computation of T ime These sections would clarify how to determine the deadlines referenced in the propos ed Transport Rule trading program rules. For example, deadlines falling on a weekend or holiday are extended to the next business day. These are the same computation
- of
- time provisions used in prior EPA- administered trading programs. (v) §§ 97.408, 97.508, 97.608, 97.708 and Part 78
-- Administrative Appeal P rocedures Final decisions of the Administrator under the proposed Transport Rule trading program rules would be appealable to EPA’s Environmental Appeals Board under the regulations that are set forth in part 78 (40 CFR part 78) and are proposed to be revised to accommodate such appeals. Specifically, the list in § 78.1 of the types of final decisions that could be appealed under part 78 would be expanded to include specific types of decisions under the proposed Transport Rule trading program rules. Further, under the approach in the exis ting part 78, an “interested person” (in addition to the official representative of owners and operators or an allowance463

account involved in a matter) may petition for an administrative appeal of a final decision of the Administrator. In order to expand t he “interested person” definition (which is currently in part 72 of the ARP regulations) and make the definition more readily accessible to readers of part 78, the definition would be removed from § 72.2, added in § 78.2, and expanded in a way that would c over the proposed trading program rules. Provisions concerning public availability of information, and provisions concerning computation of time (revised to be consistent with the requirements for computation of time used by the Environmental Appeals Boar d in types of administrative proceedings), would also be moved to § 78.2. In particular, the revised “interested person” definition would include, with regard to a decision appealable under part 78, would include, with regard to a decision appealable unde r part 78, any person who
-- in connection with the Administrator’s process of making that decision
-- submitted comments, testified at a public hearing, submitted objections, or submitted their name to be included by the Administrator in an interested per sons list. In addition, § 78.3 would be revised to allow for petitions for administrative appeal of decisions of the464

Administrator under the proposed Transport Rule trading programs. Further, § 75.4 would be expanded to state that filings on behalf of owners and operators of a covered source or unit under the proposed Transport Rule trading programs would have to be signed by the designated representative of the source or unit. Filings on behalf of persons with an interest in allowances in an account in the proposed programs would have to be signed by the authorized account representative of the account. (2) Allowance Allocations Sections 97.410 through 97.412, 97.510 through 97.512, 97.610 through 97.612, and 97.710 through 97.712 would set forth: certain information related to allowance allocation and for implementation of the assurance provisions; the timing for allocation of allowances to existing and new units; and the procedures for new unit allocations. In particular, these sections would in clude tables providing, for each state covered by the particular proposed Transport Rule trading program and for each year, the state trading budget (without the variability limit), new unit set
- aside, and one
- year and three
- year variability limits. With regard to existing units, these sections would also state that existing units would be allocated the allowances set forth in appendix A of the relevant Transport Rule trading465

program rules. These allocations would be permanent (taking into account the reductions in allocations, for the Transport Rule SO 2 Group 1 trading program, from phase 1 to phase 2) with one exception. A unit that does not operate (i.e., has no heat input) for three consecutive years starting in 2012 would continue to receive its Appe ndix A allocation for those years plus only three more years. Starting in the seventh year, the Administrator would stop recording the allocations for the unit and would instead add to the new unit set
- aside the allowances that would otherwise have been r ecorded for the non
- operating unit. Because the proposed unit
-by
- unit allocations are set forth in the “ State Budgets, Unit Allocations, and Unit Emission s Rates ” TSD cited previously, the proposed Transport Rule trading program rules do not repeat these a llocations in Appendix A to each rule. Instead, each Appendix A is reserved, and EPA proposes to include the unit
-by
- unit allocations, for each Transport Rule trading program, in Appendix A to the respective final Transport Rule trading program rules. Wi th regard to new units (and units that lost their allocations after not operating and that subsequently began operating again), the owner and operator of such units could request, by a specified deadline each year, an466

allocation from the new unit set
- aside for that year and each year thereafter. The allocation would equal that unit’s emissions

– - as determined in accordance with Part 75 (40 CFR part 75)

– - of the control period (annual or ozone season, depending on the Transport Rule trading program involved) in the preceding year. The Administrator would determine whether the total number of properly requested allowance allocations for all units in a state for a control period would exceed the amount in the new unit set
- aside for the state for the control period. If not, the Administrator would allocate consistent with all proper requests. If the total number would exceed the new unit set
- aside, the Administrator would allocate to each properly requesting unit its proportionate share of the new unit set
- aside. The Administrator would provide notice of these determinations (which would reflect these calculations rather than any exercise of discretion on the part of the Administrator) through issuance of a notice of data availability to which parties could submit objections and second notice addressing any objections. Any unallocated allowances in the new unit set
- aside would be allocated to existing units in proportion to their current allocations.467 If a unit that was not really a covered unit were
errone ously allocated allowances, the proposed provisions set forth a process under which the allocation would not be recorded or the recorded allocation would be deducted, with one exception. The exception would be if the process of determining compliance with the emission limitation for the source that includes the unit were already completed, in which case no action would be taken to account for the erroneous allocation for the control period involved. (3) Designated Representative s and Alternate Designated Representatives Sections 97.413 through 97.418, 97.513 through 97.518, 97.613 through 97.618, and 97.713 through 97.718 would establish the proce dures fo r certifying and authorizing the designated representative, and alternate designated representative , of the owners and operators of a source and the units at the source and for changing the designated representative and alternate designated representative. These sections would also describe the designated representative’s and alternate designated repre sentative’s responsibilities and the process through which he or she could delegate to an agent the authority to make electronic submissions to the Administrator. These provisions would be p atterned after the provisions concerning designated468

representati ves and alternates in prior EPA
- administered trading programs. The designated representative would be the individual authorized to represent the owners and operators of each covered source and covered unit at the source in matters pertaining to all Transp ort Rule trading programs to which the source and units were subject . This approach would ensure that one individual was required to be knowledgeable about the requirements of, and responsible for compliance with, all Transport Rule trading program. One alternate designated representative could be selected to act on behalf of, and legally bind, the designated representative and thus the owners and operators. Because the actions of the designated representative and alternate would legally bind the owners and operators , the designated representative and alternate would have to submit a certificate of representation certifying that each was selected by an agreement binding on all such owners and operators and was authorized to act on their behalf. The desi gnated representative and alternate would be authorized upon receipt by the Administrator of the certificate of representation. This document, in a format prescribed by the Administrator, would include: specified identifying information for the covered so urce and covered469

units at the source and for the designated representative and alternate; the name of every owner and operator of the source and units; and certification language and signature s of the designated representative and alternate. All submissio ns (e.g., monitoring plans, monitoring system certifications, and allowance transfers) for a covered source or covered unit would have to be submitted, signed, and certified by the designated representative or alternate. Further, upon receipt of a complet e certificate of representation, the Administrator would establish a compliance account in the Allowance Management System f or the source involved. In order to change the designated representative or alternate, a new certificate of representation would h ave to be received by the Administrator. A new certificate of representation would also have to be submitted to reflect changes in the owners and operators of the source and units involved. However, new owners and operators would be bound by the existing certificate of representation even in the absence of such a submission. In addition to the flexibility provided by allowing an alternate to act for the designated representative (e.g., in circumstances where the designated representative might be unavai lable), additional flexibility would be provided470

by allowing the designated representative or alternate to delegate authority to make electronic submissions on his or her behalf. The designated representative or alternate could designate agents to submit electronically certain specified documents. The previously
- described requirements for designated representatives and alternates would provide regulated entities with flexibility in assigning responsibilities under the Transport Rule trading programs, whil e ensuring accountability by owners and operators and simplifying the administration of the proposed Transport Rule trading programs. (4) Allowance Management System The Transport Rule trading program rules listed later would establish the procedures and requirements for using and operating the Allowance Management System (which is the electronic data system through which the Administrator would handle allowance allocation, holding, transfer, and deduction), and for determining compliance with the emissio ns limitations and assurance provisions, in an efficient and transparent manner. The Allowance Management System would also provide the allowance market s with a record of ownership of allowances, dates of allowance transfers, buyer and seller information, and the serial numbers of allowances transferred. Consistent with the471

approach in prior EPA
- administered trading program, allowance price information would not be included in the Allowance Management System. EPA’s experience is that private parties (e.g ., brokers) are in a better position to obtain and disseminate timely, accurate allowance price information than is EPA. For example, because not all allowance transfers are immediately reported to the Administrator for recordation, the Administrator would not be able to ensure that any reported price information associated with the transfers would reflect current market prices. (vi) §§ 97.420, 97.520, 97.620, and 97.720

– - Compliance and General Accounts The Allowance Management System would contain two types of accounts: c ompliance accounts , one of which the Administrator would establish for each covered source upon receipt of the certificate of representation for the source; and general accounts , which could be established by any entity upon receipt by the Administrator of an application for a general account. A compliance account would be the account in which any allowances used by the covered source for compliance with the emissions limitations and assurance provisions would have to be held. The desi gnated representative and alternate for the source472

would also be the authorized account representative and alternate for the compliance account. Using source
- level, rather than unit
- level accounts, would provide owners and operators more flexibility in ma naging their allowances for compliance, without jeopardizing the environmental goals of the Transport Rule trading programs, because the source
level approach would avoid situations where a unit would hold insufficient allowances and would be in violation of allowance
- holding requirements even though units at the same source had more than enough allowances to meet these requirements for the entire source. General accounts could be used by any per son or group for holding or trading allowances. However, all owances could not be used for compliance with emissions limitations or assurance provisions so long as the allowances were held in, and not properly and timely transferred out of, a general account. To open a general account, a person or group would have to submit an application for a general account, which would be similar in many ways to a certificate of representation. The application would include, in a format prescribed by the Administrator: the
name and identifying information of the individual who would be the authorized account representative and of any individual who would be the alternate authorized account473

representative; an identifying name for the account ; the names of all p ersons with an ownership interest with the respect to allowances held in the account; and certification language and signatures of the authorized account representative and alternate. The authorized account representative and alternate would be authorized upon receipt of the application by the Administrator. The provisions for changing the authorized account representative and alternate, for changing the application to take account of changes in the persons having an ownership interest with respect to allowances, and for delegating authority to make electronic submissions would be analogous to those applicable to comparable matters for designated representatives and alternates. (vii) §§ 97.421 through 97.423, 97.521 through 97.523, 97.621 through 97.623, and 97.721 through 97.723

– - Recordation of Allowance Allocations and T ransfers By September 1, 2011, the Administrator would record allowance allocations for existing units, based on Appendix A to each proposed Transport Rule trading program rule, for 2012 through 2014. By June 1, 2012 and June 1 of each year thereafter, the Administrator would record such allowance allocations for each proposed Transport Rule trading program for the third year after the year of the474

recordation deadline, e.g., for 2015 in 2012. Recording these allowance allocations about 3 years in advanc e of the first year for which they could be used for compliance would facilitate compliance planning by owners and operators and promote robust allowance markets, including futures markets for allowances. By September 1 (for the Transport Rule NO X and SO 2 annual trading programs and June 1, for the Transport Rule NO X Ozone Season program) of each year starting with 2012, the Administrator would record allowance allocations for that year from the new unit set
aside. Because this would occur before the allowance transfer deadline for each proposed Transport Rule trading program involved, this would still allow for trading and thereby promote robust allowance markets. The process for transferring allowances from one account to another would be quite simple. A transfer would be submitted providing, in a format prescribed by the Administrator, the account numbers of the accounts involved, the serial numbers of the allowances involved, and the name and signature of the transferring authorized account represent ative or alternate. If the transfer form containing all the required information were submitted to the Administrator and, when the Administrator attempted to record the transfer, the transferor account included the475

allowances identified in the form, the Administrator would record the transfer by moving the allowances from the transferor account to the transferee account within 5 business days of the receipt of the transfer form. (viii) §§ 97.424, 97.524, 97.624, and 97.724

– - Compliance with Emissions L imitations Once a control period has ended ( i.e. , December 31 for the Transport Rule NO X and SO 2 annual trading programs and September 30 for the NO X ozone season trading program ) , covered sources would have a window of opportunity ( i.e. , until the allowanc e transfer deadline of midnight on March 1 or December 1 following the control period for the annual and ozone season trading programs respectively ) to evaluate their reported emissions and obtain any allowances that they might need to cover the ir emission s during the control period . Each allowance issued in each proposed Transport Rule trading program would authorize emission of one ton of the pollutant, and so would be usable for compliance, for a control period in the year for which the allowance was al located or a later year. Consequently, each source would need

– - as of the allowance transfer deadline

– - to have in its compliance account, or have a properly submitted transfer that would move into its compliance account, enough allowances usable for compliance to authorize the476

source’s total emissions for the control period. The authorized account representative could identify specific allowances to be deducted, but, in the absence of such identification or in the case of a partial identification, the Administrator would deduct on a first
- in, first
- out basis. If a source were to fail to hold sufficient allowances for compliance, then the owners and operators would have to provide, for deduction by the Administrator, 2 allowances allocated for the contr ol period in the next year for every allowance that the owners and operators failed to hold as required to cover emissions. In addition, the owners and operators would be subject to discretionary civil penalties for each violation, with each ton of unauth orized emissions and each day of the control period involved constituting a violation of the Clean Air Act. EPA believes that it is important to include a requirement for an automatic deduction of allowances. The deduction of one allowance per allowance that the owners and operators failed to hold would offset this failure. The deduction of another allowance per allowance that the owners and operators failed to hold would provide an automatic penalty that could not be avoided, regardless of any explanat ion provided by the owners and operators for477

their failure, and would therefore provide a strong incentive for compliance with the allowance
- holding requirement by ensuring that non - compliance would be a significantly more expensive option than compliance. (ix) §§ 97.425, 97.525, 97.625, and 97.725

– - Compliance with Assurance P rovisions EPA proposes to include assurance provisions in the Transport Rule trading programs in order to ensure that each state would eliminate that part of its significant contribution and interference with maintenance that EPA has identified in today’s proposed action ( see section V.D.4. b previously). As previously discussed, a requirement that owners surrender allowances under the assurance provisions would be triggered only for owners of units in a state where the total state EGU emissions for a control period would exceed the applicable state budget with the variability limit. Moreover, only an owner whose units’ emissions would exceed the units’ allocations plus the owner’s s hare of the state budget with the variability limit would be subject to the allowance surrender. The process of determining, for a given control period, which states would have total EGU emissions sufficient to trigger the allowance surrender requirement, which owners would be subject to the allowance surrender,478

and whether those owners were in compliance would be implemented in a series of steps. (The dates summarized later apply to the proposed annual programs; the dates for the proposed ozone season prog ram would be earlier.) First, the Administrator would perform the calculations necessary to determine whether any states had total state EGU emissions for a control period greater than the state budget with the variability limit, applying both the 1
- year and the 3
- year variability limits discussed earlier. By June 1 (starting in 2015), the Administrator would promulgate a notice of availability of the results of these calculations and provide an opportunity for submission of objections. By August 1, the Administrator would promulgate a second notice of availability of any necessary adjustments to the calculations and the reasons for accepting or rejecting any properly submitted objections. Second, by August 15, the designated representative of every Transport Rule source in a state identified in the August 1 notice as having control period emissions in excess of the budget with the variability limit would make a submission to the Administrator that would identify: each person having (as of the last day o f the control period) a legal, equitable, leasehold, or contractual reservation or479

entitlement in the Transport Rule units at the source; and the amount of each such person’s reservation or entitlement. Third, by September 15, the Administrator would cal culate, for each state identified in the August 1 notice and for each owner of covered units in the state, the owner’s share of emissions, the owner’s share of the state budget with the variability limit, and the amount (if any) that the owner would be required to hold for surrender under the assurance provisions (i.e., the owner’s proportionate share of the excess of state emissions over the state budget with the variability limit). The Administrator would promulgate a notice of availability of the result s of these calculations, provide an opportunity for submission of objections, and promulgate by November 15 a second notice of availability of any necessary adjustments to the calculations and the reasons for accepting or rejecting any properly submitted objections. By December 1, each owner identified in the November 15 notice as being required to hold allowances for surrender under the assurance provisions would designate a compliance account of one of its covered units in the state, and the authorized account representative of the compliance account would submit to the Administrator a480

statement designating the compliance account, as the account in which the required allowances would be held. As of midnight of December 15, the owner would have to have in its designated compliance account, or have a properly submitted transfer that would move into that compliance account, the amount of allowances (usable for compliance) that the Administrator determined (in the calculations referenced in the November 15 notice) were required to be held by the owner for surrender. The authorized account representative could identify specific allowances to be deducted but, in the absence of such identification or in the case of a partial identification, the Administrator wo uld deduct allowances on a first
- in, first
- out basis. The potential effect of subsequent data revisions that would otherwise change the data used in and the results of the Administrator’s calculations referenced in the August 1 or November 15 notices discussed previously would be limited. If data used in a notice applying the assurance provisions to a given year were revised as a result of a decision in, or settlement of, litigation (such as an administrative appeal resulting in such decision or settlemen t or an administrative appeal whose results were in turn appealed in a judicial proceeding resulting in such481

decision or settlement) initiated within 30 days of the promulgation of the notice involved, then the Administrator would use the revised data for the calculations in the respective notice. Any other data revisions would not be used to revise the calculations. The revised data could be used, if relevant, in the Administrator’s calculations in future notices promulgated for a later year. If the
rev ised calculations increased the amount of allowances that an owner was required to hold for surrender, the Administrator would set a new, reasonable deadline for the owner to hold the additional allowances in the owner’s designated compliance account. The Administrator believes that this limitation on the effect of data revisions on the calculation of the amount of allowances owners would have to surrender under the assurance provisions is necessary. Because an owner’s surrender obligation would be calcul ated using large amounts of data involving all the covered units in a state (including potentially many units owned by other owners), each owner would face the potential that changes in data outside of the owner’s responsibility and control could change
-- after the December 15 allowance
- holding deadline

– in a way that would increase his surrender obligation after that deadline and put him in violation of the regulations and the Act. EPA believes that this482

potential risk would be significant enough that i t could make many owners reluctant to consider any compliance options involving even the limited interstate trading allowed under the proposed remedy. The proposal would limit this risk by having the Administrator only take account of data revisions resul ting from decisions in, or settlement of, litigation initiated soon after promulgation of the notice involved. Owners’ potential allowance surrender obligations as of the December 15 allowance
holding deadline under the assurance provisions would still be significant even with this limitation on the potential for the surrender obligations to increase after December 15 due to data revisions. As discussed previously, it would not be a violation of the CAA for total state EGU emissions to exceed the state budget with the variability limit or for an owner to become subject to allowance surrender under the assurance provisions. However, the failure of an owner to hold in the designated compliance account a sufficient amount of allowances to satisfy this all owance surrender would violate the CAA and be subject to discretionary penalties, with each required allowance that was not held and each day of the control period involved constituting a violation. EPA believes that the allowance surrender requirement al one483

-- and certainly when coupled with the potential for large discretionary penalties
-- would ensure that owners would take actions to avoid having total state EGU emissions exceed the level that would trigger the allowance surrender. (x) §§ 97.426 thro ugh 97.428, 97.526 through 97.528, 97.626 through 97.628, and 97.726 through 97.728

– - Miscellaneous P rovisions These sections would allow banking of the allowances issued in the Transport Rule trading programs, i.e., the retention of unused Transport Rul e allowances allocated for a given control period for use or trading in a later control period. Banking would allow sources to make emissions reductions beyond required levels and bank the unused allowances for use or trading later. This would encourage development of emissions reductions techniques and technologies and implementation of early reductions, stimulate the allowance markets, and provide flexibility to owners and operators. While this could also potentially
caus e emissions from sources in some states in some control periods to be greater than the allowances allocated for those control periods, the assurance provisions would limit such emissions in a way that would ensure that the part of each state’s significant contribution and interference w ith484

maintenance that EPA has identified in today’s proposed action would be eliminated. These sections also would provide that the Administrator could, at his or her discretion and on his or her own motion, correct any type of error that he or she finds i n an account in the Allowance Management System. In addition, the Administrator could review any submission under the Transport Rule trading programs, make adjustments to the information in the submission, and deduct or transfer allowances based on such a djusted information. ( 5 ) Emissions Monitoring , Recordkeeping, and Reporting . Sections 97.430 through 97.435, 97.530 through 97.535, 97.630 through 97.635, and 97.730 through 97.735 would establish emissions monitoring, recordkeeping, and reporting requirements for Transport Rule units that would result in c lear, consistent, rigorous, and transparent monitoring and reporting of all emissions . Such monitoring and reporting would be the basis for holding sources accountable for their emissions and would be e ssential to the success of the Transport Rule trading programs. This is because c onsistent and accurate measurement of emissions would be necessary to ensure that each allowance would actually represent one ton of emissions and that one ton of reported emissions from one source would be equivalent to485

one ton of reported emissions from another source. This would establish the integrity of each allowance and instill confidence in the underlying market mechanisms that would be central to providing sources wi th flexibility in achieving compliance. Moreover, g iven the varia tion in the type, operation, and fuel mix of sources covered by the proposed Transport Rule trading programs, EPA believes that emissions would need to be monitored continuously in order to ensure the precision, reliability, accuracy, and timeliness of emissions data supporting the trading programs. In §§ 97.430 through 97.435, 97.530 through 97.535, 97.630 through 97.635, and 97.730 through 97.735, EPA proposes the monitoring, recordkeeping , and reporting requirements for the Transport Rule NO X annual, NO X ozone season, SO 2 Group 1, and SO 2 Group 2 trading programs, respectively. These provisions reference the relevant sections of part 75 (40 CFR part 75), where the specific procedures and requirements for monitoring and reporting NO X and SO 2 mass emissions are found. The proposed provisions
are virtually the same as the monitoring, recordkeeping, and reporting requirements under previous EPA
- administered trading programs, e.g., the ARP and NOX Budget and CAIR trading programs.486 Part 75 was originally developed for the ARP and addressed SO 2 mass emissions and NO X emission rate. The ARP , as established by Congress in CAA Title IV, requires the use of continuous emission monitoring systems (CEMS) or an alternative monitoring system that is demonstrated to provide information with the same precision, reliability, accuracy, and timeliness as a CEMS. Subsequently, Part 75 was expanded, for purposes of the NO X Budget Trading Program under the NOX SIP Call, to address monitoring and reporting of NOX mass emissions. Under Part 75, a unit has several options for monitoring and reporting, namely the use of: a CEMS; an excepted monitoring methodology (NO X mass monitoring for certain peaking units and SO 2 mass monitoring for certain oil
- and gas
- fired units); low mass emissions monitoring for certain, non
- coal
- fired, low emitting units; or an alternative monitoring system approved by the Administrator through a petition process. In addition, under part 75, the Administrator can approve petitions for alternatives to part 75 requirements. The proposed monitoring and reporting provisions for the Transport Rule trading programs would allow use of these same options and petition procedures and would
r eference the applicable provisions in part 75. Existing Transport Rule units would be required to install and487

certify monitoring systems by the beginning of the relevant Transport Rule trading program. New Transport Rule units have separate deadlines bas ed upon the date of commencement of commercial operation. Recognizing that many of the Transport Rule units are already monitoring NO X and/or SO 2 under P art 75 through existing trading programs, continued use of previously certified monitoring systems wou ld be allowed when appropriate rather than automatically requiring recertification. The quality assurance (QA) requirements for the ARP that were mandated by Congress under CAA Title IV are codified in Appendices A and B of part 75. Part 75 specifies that each CEMS must undergo rigorous initial certification testing and periodic quality assurance testing thereafter, including the use of relative accuracy test audits (RATAs) and daily calibrations. A standard set of data validation rules apply to all of th e monitoring methodologies. These stringent requirements result in an accurate accounting of the mass emissions from each unit, and EPA provide s prompt feedback if the monitoring system is not operating properly. In addition, when the monitoring system i s not operating properly, standard substitute data procedures are applied and result in a conservative estimate of emissions for the period involved.488

This ensures a level playing field among the regulated units, with consistent accounting for every ton of emissions , and also provides an incentive to properly maintain, and meet the QA requirements for, each monitoring system . The monitoring and reporting provisions in the proposed Transport Rule trading program regulations would contain the same QA requirements and substitute data procedures as in Part 75 and would reference the applicable provisions in Part 75. Part 75 requires electronic submission, to the Administrator and in a format prescribed by the Administrator, of a quarterly emissions report con taining all of the emissions data specified in the recordkeeping provisions of Part 75. EPA has found that centralized , electronic reporting using a consistent format is necessary to ensure consistent review and public posting of the emissions data for covered units, which contribute to the integrity, efficiency, and transparency of trading programs. Further, the inclusion of all emissions data in a single quarterly report for each unit means that, if the same data are needed for multiple trading programs , the unit only needs to report it once in the form of one comprehensive report. The reporting provisions in the proposed Transport Rule trading program regulations would489

contain the same requirements for submission to the Administrator of electronic, comprehensive quarterly reports as in Part 75. 5. State Budgets / Intrastate Trading Remedy Option As noted earlier in this preamble, in addition to the remedy option included in the proposed FIPs, EPA is taking comment on two alternative options for eliminat ing all or part of the emissions in upwind states that significantly contribute to nonattainment or interfere with maintenance in downwind states. The first of these alternative options is the State Budgets/Intrastate Trading option described below. EPA is considering the relative merits of this option and requests comment on whether it should be included in the final FIPs. EPA also identifies below a number of disadvantages that raise concerns for EPA and are explained later in this section. EPA reques ts comment on these issues and their impacts on and significance for any final rule. a. Description of Option The State Budgets / Intrastate Trading option would set state - specific caps for SO 2 , NOX annual, and NO X ozone season emissions from EGUs and create separate allowance trading programs within each state in the respective regions starting in 2012 . The state
- specific caps would490

ensure that all required reductions occur within the state and thus would address the C ourt’s concerns about abating each indiv idual upwind state’s unlawful emissions under CAA section 110(a)(2)(D) (i)(I) . Similar to other trading programs, the owners and operators of each source would be required to surrender to EPA one allowance for every ton of emissions after the end of every control period. Sources within each state could trade allowances amongst themselves, but not with sources located in other states. Total emissions in e ach state could not exceed that state’s budget and there would be no shifting of emissions to other sta tes thus ensuring that each state’s contribution to nonattainment and interference with maintenance with regard to downwind states would be adequately addressed. Banking of allowances for use in a later period would be permitted under this remedy option. Under this option , EPA would allocate allowances to the covered sources within each state and the allowance holders would only be allowed to trade exclusively with others within the same state. Even a company that operate s EGUs in multiple states would no t be permitted to trade or transfer allowances to its other facilities or accounts other than those within the same state. In essence, this approach, if implemented, would result in 2 8 separate491

trading programs for NO X annual, 2 6 trading programs for NO X ozone season, and 2 8 trading programs for SO 2 for a total of 82 new trading programs to be administered by EPA. These 82 trading programs would require 82 separate sets of allowances. Companies that own EGUs in more than one state would also be responsib le for managing their allowances for each program in each state separately. Unlike the remedy option in the proposed FIPs or the other alternative remedy option, this option does not include assurance provisions based on the variability limits described in section IV. This option includes a "hard" cap for each state equal to its budget, which provides assurance that reductions will occur in each state and which EPA believes makes additional assurance provisions unnecessary. The State Budgets/Intrastate Tr ading option does allow banking and the use of banked allowances to provide sources with some degree of operational flexibility in complying with the program. Because this option includes provisions for banking emissions allowances (as does the proposed S tate Budgets/Limited Trading remedy), limited year

- to - year (temporal) emissions variability is allowed. EPA requests comment on this approach to providing emissions variability. EPA also requests comment on whether492

assurance provisions based on variabili ty limits should be included in this option. b. How the Option Would be I mplemented (1) Applicability Applicability would be the same for the proposed remedy and for the two alternative options, including this
one . Refer to section V.D.4 above for detaile d discussion on applicability. (2) Allocation of Emission s Allowances While the general approach for calculating allowance allocations would be the same as described above for State Budgets/ Limited T rading , EPA would not distribute all of the allowances i nto the source accounts each period. The distribution of allowances would be modified because of the concentrated nature of numerous state power markets. The electric power sector tends to be highly concentrated and within a state, the majority of generati on is often owned by a relatively small number of companies. This assessment of state electricity markets is supported by analysis u sing the Herfindahl
- Hirschman Index, a way to measure the size of firms in relation to the industry and an indicator of the amount of competition among them (See Electric Generation Ownership and Market Concentration Technical Support Document). To address this potential weakness in493

the allowance markets in numerous states through allocations, under this option s ome allowance s would be withheld from certain sources in each state that control a large share of fossil
- fueled power generation, and made available for companies with a small share of generation in the state . The reason for including this provision is that t he domin ant power generation companies in each state would likely receive a large share of the allocated allowances and as a result may be able to exert control over allowance prices in the state ’s allowance market. This market power and potential for allowance p rice manipulation could pose a threat to the transparen cy and liquidity of allowance markets and put small owners of fossil
- fuel fired generation at a disadvantage regarding their compliance costs unless the owners were given sufficient access to allowance s other than through direct purchase from the state’s dominant companies . Some of these owners of a small share of generation may already face higher control costs, higher transaction costs, and less flexibility regarding compliance options. Moreover, t he use of allowance market power to manipulate prices could have wider impacts on electricity markets as a whole, electricity prices, and electricity494

reliability both within and across state borders. Therefore, the State Budgets / Intrastate Trading approach needs to address the potential for excessive market power and ensure that allowances will be available to all covered
sources at reasonable market prices . In order to address the potential market power issue, under this option, not all allowances would b e allocated using the allocation method described above in section V.D.4. Rather, a small portion of allowances would be withheld from companies with a large share of a state’s total fossil
- fuel fired electricity generation. These allowances would be made available for purchase by companies with a small share of generation through an annual auction. EPA is soliciting comments on whether a potential market power problem could arise or reasons why market manipulation would not be a concern under this alte rnative remedy. EPA is also soliciting comments on whether the approach of using an annual auction to make allowances available to small generators would satisfactorily address this potential issue. This approach is detailed in subsection (3) below. The approach described for new unit set
- asides and allocations to non
- operating units above for State495

Budgets/Limited Trading in section V.D.4 would remain the same for this option. (3) Auction of Emission s Allowances The use of an annual allowance auction wou ld ensure that companies with a small market share in a state would have access to additional allowances, if needed, other than through direct purchase from a large owner of generation and would reduce the opportunity for market price manipulation by domin ant companies. This means that EPA would hold a total of 82 auctions every year to separately auction SO 2 and NOX ozone season and NOX annual allowances in each of the 82 intrastate trading programs. The auction format would be single
- round, uniform
-pric e, sealed bid with an initial reserve price of 70 to 80 percent of the modeled allowance price. Reserve prices would be updated at regular intervals to reflect changes in average market prices over time. Any unsold allowances would be returned to the sour ces from which they were withheld on a proportional basis. Revenues from the auctions would be deposited in the U.S. Treasury, in accordance with 31 U.S.C. section 3302. EPA would use auctions to address market power concerns rather than other options it considered. The Agency considered using a different allowance allocation496

method that would take into account an owner’s share of total generation and distribute proportionally more allowances to owners of a small share of the total generation in each stat e. This would also ensure that small owners had sufficient allowances without relying on the open markets. However, EPA opted to use an allocation methodology based directly on the approach used to quantify each state’s significant contribution to ensure that a direct link exists between allocations and significant contribution to nonattainment or interference with maintenance. EPA also considered direct sales of allowances withheld from dominant sources but believes that auctions would be better suited for determining the appropriate prices for allowances than EPA would be at setting fixed allowance prices for all trading programs in all states. For these reasons, EPA believes the use of auctions would be the best method to address the issue of potentia l allowance market manipulation. EPA prefers to use the single
- round, uniform
-price, sealed bid format because it is simple for all participants to understand, relatively simple to implement and administer, and deters collusion among bidders. In addition , the utility sector already is familiar with this type of format, and EPA has several years of experience497

running single
- round, sealed
-bid auctions for SO 2 . Other formats considered such as multi
- round auctions are believed to be more complicated for par ticipants to understand, more complex to administer and do not discourage collusion. Further, it is not assured that another format would maximize revenue compared to EPA’s suggested format. Entities that meet the following criteria would be eligible to participate in the allowance auction : (1) they
are required to hold allowances in the state for compliance ; and (2) they own no more than 10 percent of the total fossil
- fuel fired generation within the state based on EPA’s modeled generation for 2014 . EPA considered a range from 5 to 20 percent share of ownership for all states and believes that 10 percent ownership is appropriate for determining what constitutes a small market share for this rule. EPA believes that by limiting the auction to entities tha t own no more than 10 percent of the fossil
- fuel fired generation in a state, it would ensure that each auction has enough participants to make auctions viable and competitive and also ensure that the allowances are available only to those companies that may be at a disadvantage in the open markets. Companies with more than a 10 percent share of generation tend to operate several498

units, have more flexibility, receive a significant share of allowances, and face lower control and transaction costs. EPA is e xplicitly requesting comment on the share of electric generation used as a threshold for determining participation in auctions and also the percentage of allowances available through auctions. To implement this option, EPA would withhold 2 to 5 percent of the allowances that would be allocated to companies with more than 10 percent of the generation in order to supply allowances for auction each period . This amount is small enough not to have a significant impact on those EGUs from which the allowances are withheld and large enough to provide a sufficient number of allowances for auction. In more highly concentrated states where few companies control much of the generation, a relatively greater number of allowances would be available through the auction to the smaller, potentially disadvantaged companies. Conversely, in states where the electricity sector is less concentrated, there is less threat of market manipulation and greater likelihood of liquid markets . Thus, in these states relatively fewer allowances would be withheld for auction. Another variation on this alternative approach would be to divide companies in each state into three groups,499

instead of just two. The first group would be the companies that own no more than 10 percent of the total fos sil
- fuel generation within the state and would be able to participate in EPA’s allowance auctions. The second group would be companies that own a medium amount of fossil
- fuel fired generation (for example, between 10 to 20 percent of the total). These companies would not be allowed to participate in auctions but also would not have to contribute any allowances to the auctions. Finally, the third group would be those remaining companies that own a large share of fossil
- fuel generation (for example, more than 20 percent of the total) . A small percentage of the allowances allocated to these companies would be withheld to supply the auctions. EPA is asking for c omments on this alternative and other ways to address potential market power problems and on this alternative approach. ( 4 ) Allowance Management S ystem The allowance management system for the State Budgets / Intrastate Trading option would be consistent with the allowance management system for the State Budgets/ Limited T rading programs described above, and with the data system structure EPA has developed for allowance management under its existing cap and trade programs such
as the CAIR and the Acid Rain Program.500

( 5 ) Monitoring and Reporting Monitoring and reporting provisions would require complete, qua lity
- assured monitoring, and timely reporting of emissions to assure accountability and provide public access to data, and would be the same for EPA’s proposed remedy and the State Budgets / Intrastate Trading option . Refer to section V.D.4 above for detail ed discussion on monitoring and reporting requirements. ( 6 ) Penalties Under the State Budgets / Intrastate Trading option for an annual control program (i.e., any of the 2 8 SO 2 or 2 8 NOX annual programs), the requirement that each source hold in its compliance account one allowance for each ton of emissions, and the penalties for failure to meet this requirement, would be the same as described previously in the Penalties section for the State Budgets/ Limited T rading remedy option. However, because sources i n a given state can only use allowances issued for that state, the penalties associated with failure to hold one allowance for each ton of emissions are adequate to ensure that emissions from the state do not exceed the state budget (except for
some tempor al variability due to banking). For this reason, EPA does not believe that any other penalties or assurance provisions (such as the assurance provisions used501

in the State Budgets/ Limited T rading remedy) are necessary to ensure that each state eliminates the portion of significant contribution and interference with maintenance that EPA has identified in today’s action . EPA requests comment on this conclusion. c. How the State Budgets / Intrastate Trading Remedy is C onsistent with the Court’s Opinions The sta te budgets /intrastate trading remedy , by establishing state
- specific caps on annual or ozone
- season EGU emissions, directly implements the section 110(a)(2)(D)(i)(I) requirement th at emissions from sources that contribute significantly to nonattainment in, or interfere with maintenance by, any other s tate with respect to any such national primary or secondary ambient air quality standard be prohibited . Of the three remedy options considered, this option provides the most certainty regarding total annual or ozone - season emissions from each state. For this reason, it most directly addresses the statutory mandate that the emission reductions occur “within the State.” To implement this remedy option, EPA would use the state budgets without variability limits, developed in accordance with the procedures described in sections IV.D and IV.E. These budgets represent EPA’s projection of each502

affected s tate’s EGU emissions in an average year ( before accounting for the inherent variability in power system operations ) after the elimination of all emissions that EPA has identified as significantly contribut ing to nonattainment or interfere nce with maintenance. The number of allowances in each state budget would be distributed or made available (through an auction or ot herwise) to sources in that state. Only allowances distributed or made available to sources in a particular state could be used by sources in that state to satisfy the requirement to hold one allowance for every ton of emissions. Thus, annual (or ozone s eason) emissions in the state would be capped at the level of the state budget. The limited variability due to banking of emissions could allow limited temporal shifting of emissions, but would not alter the requirement that reductions occur within the st ate. This remedy is thus sufficient to ensure that all significant contribution and interference with maintenance identified by EPA in today’s action is eliminated. d. Electric Reliability I ssues EPA requests comments about whether t he State Budgets / Intr astate Trading alternative option could have adverse consequences for electric reliability. The grid regions, and the movement of electricity within each grid503

region, do not correspond with, and are not limited by, state borders. For example, an increase in electricity demand (e.g., due to a hot summer), or a decrease in electricity supply (e.g., due to a major generation capacity outage), in a given state will not necessarily be met, or offset, through increased electricity generation in that same state. Instead, the increased demand or reduced supply may well result in increased generation outside that state. The sources of the increased generation will be determined by availability and economics and will not necessarily be confined to generation source s in that state. In fact, the ability to obtain additional or replacement supply from sources in another part of the state or from another state enhances electric reliability. Although companies in one state obtain electricity from sources in multiple sta tes, the State Budgets / Intrastate Trading option would establish emissions budgets on a state basis and would not allow sources in one state to use allowances issued to sources in other states . A source could use, in covering emissions for the current yea r, both allowances allocated for the current year and banked allowances issued by its state for a past year. However, this option would provide sources less trading flexibility than the proposed State Budgets/ Limited T rading504

remedy. T he other remedy opti ons allow for emissions variability, which should largely address electric reliability concerns. EPA requests comment on whether the State Budgets / Intrastate Trading alternative would provide sufficient flexibility for reliable operation of the integrate d grid and, if not, whether there would be ways of preventing or reducing adverse effects such as including additional emissions variability provisions in this option or other approaches. EPA requests comment on approaches to provide additional emissions variability, or other approaches to increasing flexibility, in this option that would be consistent with eliminating all or part of the significant contribution and interference with maintenance that EPA has identified . e. How Smaller Market T rading P rograms H ave Worked These examples of small trading programs below are relevant to further understanding of the State Budgets / Intrastate Trading remedy option. While small trading programs can succeed, they can also have serious consequences for allowance and electricity markets. Budgets and caps, allowance availability, and prices all can have a profound impact on generation and energy prices for consumers in addition to any air quality benefits. In505

addition, states range in size and number of potential prog ram participants making each state’s circumstances unique and more challenging for EPA to monitor. (1) T exas Mass Emissions Cap and Trade (MECT) EPA has approved a NOX cap and trade program as part of an ozone attainment SIP for the Houston Galveston Brazo ria (HGB) nonattainment area in Texas. The program knows as the Mass Emissions Cap and Trade (MECT) program establishes a mandatory NO X annual emissions cap for stationary facilities in the HGB area located at sites with a collective uncontrolled design c apacity to emit 10 tons per year or more of NO X . The MECT program source population is relatively small but very diverse and covers, among others, EGUs, refineries, chemical plants, and industrial and commercial boilers. The diverse source population all ows the MECT program to be a viable means of reducing NO X emissions without impacting electric reliability. Overall, the MECT program has not encountered major problems caused by its small size and has resulted in environmental benefits for the HGB area. The MECT program establishes a hard cap for NO X emissions at a level modeled as necessary for the area to reach ozone attainment. The MECT program started January 1, 2002 and the NO X cap stepped down each subsequent year506

until reaching the final cap level of 80 percent of the baseline NO X emissions in January 2007. In the MECT program one allowance is equivalent to one ton of NO X emissions. Allowances are allocated to existing facilities on January 1 of each control period, which spans the calendar year. Facilities that do not receive allowances as “existing facilities” (those in operation at the time of program inception) must purchase excess allowances from other covered sources to operate and demonstrate compliance. All covered sources are required to hold sufficient allowances at the end of each control period to equal NO X emissions during the same time period. Allowances can be used in the control period of allocation, traded to another covered source in the MECT for use in the same time period, or banked for use in the following control period. Allowances can be traded in one of four ways: vintage trades, current year trades, individual future year trades, or stream trades. Vintage trades involve the immediate transfer of vintage allowances. Cur rent year trades involve the immediate transfer of current allowances. Individual future year and stream trades involve the transfer of future allowances, with stream trades involving a transfer of allowances in perpetuity. Analysis conducted by the Texas Commission on Environmental Quality of the507

MECT program trading history shows that approximately 20 percent of the allowances allocated each year are traded and that nearly 50 percent of all program participants have participated in allowance trading. Al lowance prices are set by market demand. Prices of individual year allowances have steadily increased as the program has progressed, showing that the value of the allowances increases as the cap tightens. Stream trade prices have fluctuated throughout the program, but have steadily increased as the final cap level has been reached. (2) Re gional C l ean Air Incentives Market (RECLAIM) In comparison to MECT, RECLAIM is a small trading program that has faced a number of challenges due to initial program design decisions. In 1994, RECLAIM established a cap and trade program for NO X and SO 2 emissions as part of an effort to improve air quality in the Los Angeles area. Every year the caps decline to meet the objective of getting the area into compliance with
ozone and particulate matter NAAQS. One noteworthy feature of the RECLAIM trading programs is the two overlapping cycles. Roughly equal numbers of facilities we re assigned to each of the two compliance cycles. Facilities in compliance cycle 1 complete their twelve month cycle at the end of the calendar year (December 31), while facilities in508

compliance cycle 2 complete their twelve
-month cycle at the end of the fiscal year (June 30). Around 300 facilities have participated annually in the RECLAIM NO X trading p rogram. Every facility then complied using valid credits of either cycle , but banking of allowances for use in a later period was not allowed. RECLAIM T rading C redits (RTC) prices for NOX rose from about $3,000 per ton early in 2000 to nearly $20,000 per ton in June and up to about $70,000 per ton in August of that year . P rices of RTCs during the California energy crisis during 2000 and 2001 averaged in the $50,000 per ton range. 98 While the California crisis was the result of several malfunctions in the market, the RTC price spike was exacerbated by a number of factors starting with the fact that few emissions reductions had been made in earlier years. Prior to the California crisis, RTCs had been over
allocated, RTC prices had remained low, and utilities had taken little action to install costly controls. When emissions increased and exceeded the level of allocated RTCs, prices shot up to very high levels. In addition, there has been speculation that high RTC prices at the time

98 Joskow, Paul and Edward Kahn, 2002. A Quantitative Analysis of Pricing B ehavior In California’s Wholesale Electricity Market During Summer 2000: The Final Word.509

were partly caused by the high demand for credits resulting directly from the manipulation of the power market by generators . 99 The operation of the RECLAIM market also contributed to the high prices in the overall power markets. During this period, generators would pay excessivel y high prices for RTCs in order to raise the price of s outhern California generation needed to meet demand in the California I ndependent S ystem Operator (CAISO). Subsequently, generation with high RTC costs in the RECLAIM area would be used to set the ele ctricity price for all of California . The result was that generators could then collect excessive profits on their generation located outside the RECLAIM
area . In addition, RECLAIM’s overlapping compliance cycles and assignment of facilities to one of two compliance cycles appears to have contributed to some confusion among the participants in the markets . 100 Since that time, significant changes have been adopted to improve the program.

99 Kolstad, Jonathan T. and Frank A. Wolak, 2003. Using Environmental Emissions Permit Prices to Raise Electricity Prices: Evidence from the California Electricity Market. Published by University of California Energy Institute. 100 Holland, Stephen P. and Michael Moore, 2008. When to Pollute, When to Abate? Intertemporal Permit Use in the Los Angeles NO X Market. Published by University of California Energy Institute.510 According to the audit report for the 2007 compliance period, t otal aggregate NO X emissions were below total allocations by 21 percent and total aggregate SO X emissions
were below total allocations by 13 percent . S ince January 2008 , NOX RTCs prices have been declining and have not exceeded $15,000 per ton . f. Why This is no t the P referred Option As explained above, EPA is requesting comment on a State Budgets / Intrastate Trading remedy as an alternative option because this option would provide certainty regarding emissions from each state. However, this option would be more resource intensive, more complex, less flexible, and potentially more susceptible to market manipulation than the other options on which EPA is taking comment . Although this remedy may be perceived as relatively easy to understand and follow, it would ac tually be more burdensome to administer due to the number of trading programs that would be required to operate simultaneously and annual auctions that would be held every year to address the issues of market power within states. It would also result in a greater burden for participants operating EGUs in several states. Finally, EPA is asking for comment on whether this option raises electric reliability issues511

since sources would have less flexibility and fewer options for compliance. EPA is requesting comments on this approach , specifically on alterations that could address the drawbacks identified above or on any other weaknesses of this option not identified by EPA. EPA also welcomes comments regarding the validity of the concerns with this approach identified above. 6. Direct Control Remedy Option The second alternative option EPA is requesting comment on is the direct control option described later. EPA is considering the relative merits of this option and requests comment on whether a direct cont rol remedy option should be included in the final FIPs. There are a variety of ways to construct a direct control option. The approach that EPA is presenting as an alternative to the remedy in the proposed FIPs would assign emission rate limits to indiv idual sources. Emissions limits would take the form of input
-based emissions rate limits (lb/mmBtu). EPA explicitly requests comments on the direct control remedy summarized later and the approach for determining emission rate limits, which is described i n greater detail in the “ State Budgets, Unit Allocations, and Unit Emissions Rates ” TSD in the docket for this rulemaking.512

Specifically, EPA requests comment on the general use of a direct control remedy as well as the specific rate
-based direct control approach described later. EPA also requests comment on the potential weakness of this remedy option identified in the discussion later. In addition, EPA requests comment on alternate methodologies which could be used to implement a direct control remedy. See section V.E . later for projected costs and emissions associated with this option. a. Description of Option Unlike the proposed remedy option (State Budgets/Limited Trading) and the other alternative remedy option (Intrastate Trading) discussed previous ly, which both use flexible cap
- and
- trade approaches, a direct control remedy would directly regulate individual sources. Under th is direct control remedy alternative , each owner of EGUs would be required to meet specified average emission rate limits covering all of its EGUs in each covered state. In a state covered for the 24
- hour and/or annual PM2.5 NAAQS, the direct control remedy option would require each company within the state to meet specified EGU annual emission rate limits for SO 2 and NOX . In a state covered for the 8
- hour ozone NAAQS, this remedy would require each company within the state to meet specified EGU ozone season513

emission rate limits for NO X . EPA would set emission rates on a unit
-by
- unit basis in all covered states ( see approach t o determine emission rate limits, later). While emission rates in all states would be set on a unit
-by
- unit level, a company would be allowed to average the emissions at its units within each state to meet the specified within
- the
- state rate limits. Company - level average rates would be calculated as company
- level total emissions divided by company
- level total heat input in each state. Analogously, allowable company
- level average rates would be calculated using unit
- specific rate limits and the heat inputs used to determine those allowable rates (as discussed in 6.b.1). A company that exceeded the applicable average rate limits would be subject to penalties (described later ). In addition, to address the potential variability in annual emissions associated with emission rate limits (i.e., not all years are average) , starting in 2012, each state’s total annual (or ozone season, as applicable) EGU emissions would also be capped. Emissions from EGUs in each state would be limited to the state’s emissions budge t with the variability limit . Each state’s EGU emissions would be capped in the following two ways: First, the state’s EGU emissions would not be permitted to exceed the514

state budget with the state’s 1
- year variability limit in any year (or ozone season, as applicable). Second, on average, the state’s EGU emissions would not be permitted to exceed the budget with the state’s 3
- year variability limit , evaluated as a 3
- year rolling annual (or ozone season) average (or, in SO 2 group 1 states during 2012 and 2013, a 2
- year rolling average) . See section IV.E for lists of each state’s emissions budgets. Section IV.F describes EPA’s proposed approach to variability. Tables IV.F - 1 through IV.F
- 3 present 1
- year and 3
- year variability limits. Table IV.F
- 4 prese nts 1
- year and 2
- year variability limits for SO 2 group 1 states during 2012 and 2013.If total EGU emissions in a state exceed either of these limits (i.e., budget with 1
- year variability limit in any year, or budget with 2
- or 3
- year variability limit on average), then each company with units in the state whose emissions in the state exceeded their share of the state budget with variability limit would be subject to a penalty. These assurance provisions are designed to assure that emissions in each cover ed state do not exceed the state’s budget with variability limit. They are described later . EPA also believes the penalty provisions described515

later are sufficient to ensure that these caps would not be exceeded. To implement this remedy option, EPA woul d determine unit
- level emission rate limits for SO 2 , NOX annual, and NO X ozone season at levels such that, if the units operated at the levels assumed in determining the state budgets, total emissions from these units would sum to each state’s emissions bu dget(s) without the variability limit . The method for determining these rate limits is described later. An alternative direct control approach would be to create individual unit
- level annual emissions caps (e.g., tons/year) in order to cap emissions in ea ch state. However, t his approach would greatly limit operational flexibility and increase risk to electric reliability. For example, a unit
- level annual emissions cap approach could prevent a peaking unit from running at a time when the unit is necessary for electric reliability. EPA does not believe that a unit
- level annual emissions cap approach is workable. b. How the Option Would be I mplemented (1) Approach to Determine Emission Rate Limits To implement this remedy option, EPA would determine unit
- level emission rate limits for SO 2 , NOX annual, and NO X516

ozone season, for covered EGUs in the covered states. Emission rate limits would be set at levels such that, if the units operated at the levels assumed in determining the state budgets, total emission s from these units would sum to the state budgets. In a state covered for purposes of the PM2.5 NAAQS, EPA would determine SO 2 and NOX annual emission rate limits for each covered EGU. In a state covered for purposes of the 8
- hour ozone NAAQS, EPA would determine NO X ozone season emission rate limits for each covered EGU. Emission s rate limits for Phase I (2012 and 2013) . S tate budgets were derived from the lower of available 2007
- 2009 quarterly emissions or IPM base case projections for 2012 , at the sta te level . Analogous to state budget calculation, EPA would base the Phase I annual emission rate limit on either the unit’s reported annual emissions rate or the IPM projected rate . Rates based on reported data would be calculated using the most recent f irst, second, third, and fourth quarters of emissions data reported to EPA, between the first quarter of 2007 and the third quarter of 2009, where four such quarters of reported data are available. EPA would determine ozone season rates based on a unit’s most recent ozone season emissions reported to EPA during the period of 2007
- 2009, if517

available, and projections or source
- specific judgments otherwise. For units where EPA is aware that SO 2 or NOX controls will be installed by 2012 and such controls were not reflected in the unit’s reported emission rate as determined previously (i.e., the control was not in operation during the period of time which emissions limits were based upon), EPA would determine the Phase I emission rate limit as the historic rate adjusted (reduced) to reflect operation of the planned control equipment at an emission rate consistent with operation of that equipment. Emission rate limits would be determined based on the assumption that units operate all existing SO 2 and NOX control equipment, and the assumption that the type of fuel used does not change from that used in determining the unadjusted rate limit. For those EGUs which did not report a first, second, third, and fourth quarter of SO 2 , NOX , and/or a complete ozone season of NOX emissions data to EPA during the 2007
- 2009 period, or for those units located in states where budgets are based on IPM projections, EPA would determine emission rate limits based on modeling projections. Based on the analysis conducted for this propos ed rule, EPA would use modeling projections to determine SO 2 rates for518

approximately 1,600 units, annual NO X rates for 1,800 units, and ozone season NO X rates for 1,900 units. EPA seeks comment on the ability of all such units to achieve these limits base d on IPM projections. See table entitled “Phase I and Phase II unit
- level emission rate limits” located in the “ State Budgets, Unit Allocations, and Unit Emissions Rates ” TSD in the docket for this rulemaking. For those units that did not report data for a given pollutant and time frame combination and also were not included in IPM modeling, EPA would need to determine permissible rates based on unit characteristics (e.g., types and sizes of units, fuel type). The approach would also need to take into ac count the variety of controls and measures that can be used to limit emissions, including available fuels. While EPA does not believe that such units exist, EPA is taking comment on the existence of units that did not report first, second, third, and four th quarter data to EPA between the first quarter of 2007 and the third quarter of 2009, and are not included in IPM modeling. If EPA is made aware of such units, the unit
level analysis required to establish such limits would be extremely complex, and cou ld impact the ability of EPA to require the reductions as quickly as under other remedy approaches.519 EPA is also taking comment on an alternative approach for setting emission rate limits for those units which did not report a first, second, third, and fo urth quarter of SO 2 , NOX , and/or a complete ozone season of NO X emissions data to EPA during the 2007
- 2009 period. In this alternative approach, EPA could develop specific limits that would apply to a large group of units with varying characteristics. The numerous variables that contribute to differences in units’ emissions rates complicate development of limits for a large group of units. Therefore, to ensure that all units in a broadly
- defined group could achieve their rate limits, it would be
necessar y to either establish limits that are fairly weak so that the poorest
-performing units could meet the requirements (“lowest
- common - denominator” effect), or, design more stringent requirements but include provisions for exceptions to the requirements. At t his time, EPA believes using IPM projections and source
- specific judgments is preferable to the alternative of group
-based limits, and seeks comments on this alternative. Emissions rate limits for Phase II (2014 and onward) . For EGUs in states that are in SO 2 group 1 (i.e., the more stringent SO 2 group), EPA would further adjust (reduce) SO 2 emission rates for certain EGUs that EPA projects would520

install FGD in modeling of the proposed remedy option (at less than $2000 per ton); for such units EPA would det ermine emission rate limits at rates consistent with FGD operation. For other covered units, Phase II emission rate limits would be the same as Phase I limits. Again, emission rate limits would be determined based on the assumption that units operate all existing SO 2 and NOX control equipment, and that the type of fuel used does not change from that used in determining the unadjusted rate limit. Note that for ozone season NO X there is only one phase. Emissions rate limits for new units. The emission rat e limits for covered new units would be set equal to the permit rates for these units. EPA has calculated specific emission rate limits for each existing unit that would be covered under this direct control remedy option. These unit
- level emission rate limits appear in a table entitled “Phase I and Phase II unit
- level emission rate limits” located in the “ State Budgets, Unit Allocations, and Unit Emissions Rates ” TSD in the docket for this rulemaking. More detailed description of the approach is also prov ided in the TSD. EPA is requesting comment on this approach for determining the521

emission rate limits described in the TSD and on the limits themselves. (2) Applicability Applicability would be the same for all three remedies. Refer to section V.D.4 previ ously for detailed discussion on applicability. (3) Monitoring and Reporting Monitoring provisions would be the same for all three remedies. The direct control option would require minor changes to the reporting and record keeping requirements due to the need to collect information on both emissions rates and mass. The provisions would require complete, accurate measurement and timely reporting of emissions to assure accountability and provide public access to data. Refer to section V.D.4 previously for detailed discussion on monitoring and reporting requirements. (4) Assurance P rovisions As discussed previously , starting in 2012, the direct control remedy alternative would include assurance provisions designed to assure that emissions in each covered state do not exceed the state’s emissions budget with variability limit . The state’s EGU emissions would not be permitted to exceed the state budget with 1
- year variability limit in any year (or ozone season, as522

applicable ) . Additionally , on a 3
- year rol ling average basis , the state’s EGU emissions would not be permitted to exceed the budget with the 3
- year variability limit (evaluated on an annual or ozone season basis, as appropriate) . Furthermore, during 2012 and 2013, SO 2 emissions from EGUs in group 1 states (i.e., the more stringent SO 2 group) would not be permitted to exceed the budget with the state’s 2
- year variability limit , evaluated
as a 2
- year rolling annual average. Section IV.E in this preamble lists each state’s emissions budget, and sect ion IV.F lists the 1
- , 2
- , and 3
- year variability limits, as applicable. Note that for EGUs in states that are in SO 2 group 2 (i.e., the less stringent SO 2 group) and/or states required to reduce NO X emissions, EPA would apply only the 1
- year variability l imit in 2012 and 2013, and not the 3
- year variability limit. Because emissions would be evaluated against the 3
- year variability limit on a 3
- year rolling average basis, the application of the 3
- year variability limit in 2014 would also serve to limit emi ssions in 2012 and 2013. For EGUs in SO 2 group 1 states (i.e., the more stringent SO 2 group) EPA would apply a different 1
- year SO 2 variability limit in 2012 and 2013 than for 2014 and later. Furthermore, in these group 1 states, EPA would apply a 2
-523

year SO 2 variability limit in 2012 and 2013, and a 3
- year limit for later years (section IV.F discusses why variability limits for the group 1 states would differ in 2012 and 2013). If total EGU emissions in a state exceed either the state’s budget with 1
- year variability limit in any year, or budget with 3
- year variability limit (or 2
- year, as appropriate) on average, then each company with units in the state whose emissions in the state exceeded its share of the state budget with variability limit would be subject to a penalty for its share of emissions above the budget with variability limit . In the State Budgets/Limited Trading remedy described previously , the proposed assurance provisions include an allowance surrender requirement. Th os e assurance provisio ns would require a company to surrender one allowance for each ton of the company’s proportional share of the amount the state’s EGU emissions exceed the budget with variability limit . This allowance surrender requirement is in addition to the trading pro gram requirement to surrender one allowance for every ton emitted. In the direct control alternative, however, allowances are not allocated to units therefore an allowance surrender524

requirement is not feasible. Instead, for this alternative, a company wit h emissions over its share of the budget with variability limit would be in violation of the CAA and subject to discretionary penalties. The tonnage amount of the company’s violation, i.e., the company’s excess emissions under the assurance provisions, wo uld be its proportional share of the amount that the state’s EGU emissions exceed the budget with the variability limit. Each ton of the company’s excess emissions , as well as each day in the averaging period, would be a violation. In this direct control remedy alternative, a company’s share of the state budget with variability limit would be determined using the same approach described in the State Budgets/Limited Trading option, previously . That approach is based on allowance allocations; although the d irect control remedy would not allocate allowances to sources, this remedy would use the allocation method described in State Budgets/Limited Trading in determining a company’s share of the state budget. The assurance provisions would commence in 2012 for this direct control option . In contrast and for the reasons explained in section V.D.4, for the proposed State Budgets/Limited Trading remedy, EPA is proposing to start applying the assurance provisions in 2014. The combination525

of circumstances for State Budgets/Limited Trading

—known locations of controls and a price on each ton emitted

— provides greater certainty of where reductions will occur during 2012 and 2013 than would be provided by the direct control program. In contrast to the State Budgets/Limi ted Trading remedy, the direct control program does not put a price on emitting SO 2 or NOX so does not provide that incentive to reduce emissions. Sources can increase generation, while meeting the emissions rates limits, and increase their emissions. Fo r these reasons, the direct control program provides less certainty regarding the location of emissions in the short term. For this reason, EPA believes that it would be appropriate to apply the assurance provisions under this remedy option beginning in 2 012. EPA requests comment on these assurance provisions. (5) Penalties As explained previously , under this direct control remedy approach, each owner of EGUs within a covered state would be required to meet specified average emission rate limits for SO 2 and/or NO X emission for all of its EGUs. For the annual SO 2 or NOX control programs, if a company were to exceed the applicable company - wide annual average rate526

limit , it would be in violation of the CAA and subject to discretionary civil penalties. The ex cess emissions of the owner’s EGUs would be calculated as the EGUs’ actual annual average emission rate minus the applicable annual average emission rate limit, with the difference multiplied by the EGUs’ total actual annual heat input. Each ton of excess emissions, as well as each day in the averaging period (e.g., 365 days for an annual program), would be a violation of the CAA. The maximum discretionary penalty under CAA Sec tion 113 is $25,000 (inflation
- adjusted to $37,500 for 2009) per violation. For the ozone season NO X program, the penalty provisions would work in the same manner described herein except on an ozone season basis rather than annual. In addition, any company with EGU emissions exceeding its share of the state budget with variability limit for SO 2 , NOX annual or NO X ozone season would also be in violation of the CAA and subject to discretionary civil penalties explained earlier in this section if, in any year (or ozone season, as applicable), the state as a whole exceeds its budget with variability limit ( see description of assurance provisions, previously ). EPA requests comment on the penalty provisions.527

c. How the D irect C ontrol Remedy is C onsistent with the Court’s Opinions The direct control remedy option would implement the section 1 10(a)(2)(D)(i)(I) requirement that “emissions from sources that contribute significantly and interfere with maintenance in downwind nonattainment areas” be prohibited. It would do so by establishing for covered EGUs specific emission rate limits, with company - wide within state averaging. Emission rates in all states would be set on a unit
-by
- unit basis at levels such that, if the units operated at the levels assumed in determining the state budgets, total emissions from these units would sum to each state ’s emissions budget(s) without the variability limits . A company could average the emissions at its units within each state to meet specified within
- the
- state rate limits. This approach would directly limit emissions from EGUs in each covered state, prov iding assurance that emission reductions would occur within each state consistent with the mandate of section 110(a)(2)(D)(i)(I). Because individual EGU s would be required to meet specific emission rate limits (with within
- state company wide averaging), th is option would ensure that required controls and measures are installed and implemented within the state . The fact that emissions, after implementation528

of all controls required to meet the emission rate limits, may vary based on the amount of generation in each s tate is not inconsistent with the section 110(a)(2)(D)(i)(I) requirement that all significant contribution and interference with maintenance be eliminated. As noted previously , changes in generation due to changing meteorology, demand growth, or disruptions in electricity supply from other units can all affect the amount of generation needed in a specific s tate and thus the baseline emissions from that s tate. Because baseline emissions are variable, emissions after the elimination of all signific ant contribution are also somewhat variable. Further, any such variation in emissions would be limited. As with the State Budgets/Limited Trading option described previously , no s tate’s EGU emissions would be permitted to exceed the state budget with vari ability limit in any year (or ozone season, as applicable). Nor would any state’s EGU emissions be permitted, on average, to exceed the budget plus a specified portion of the state’s variability limit , evaluated as a 3
- year rolling annual (or
ozone season ) average (or, in SO 2 group 1 states during 2012
- 2013, a 2
- year rolling annual average) . Section IV in this preamble lists each state’s emissions budget, and 1
- , 2
- , and 3
- year variability limit, as applicable.529

d. Electric Reliability I ssues The risk to e lectric reliability is considered low under the Direct Control remedy option . Specifically, the provisions for the variability limits and company averaging within each state help to alleviate electric reliability concerns. Therefore, EGUs are expected to be able to both comply with their emission rate limits and reliably provide electricity to customers. EPA requests comment on electric reliability issues.
e . Why This is Not the Preferred Option As explained previously , EPA is requesting comment on the merits and weaknesses of this direct control remedy option. EPA did not include this remedy option in the proposed FIPs; however, we continue to consider this option and are taking comment on whether this option should be included in the FIPs. This option would provide assurance that companies in each state are meeting specific emission rate limits and would also ensure that annual emissions from each state are capped. Additionally, the direct control option may be perceived as easy to understand and foll ow. Nonetheless, at this time, EPA believes the direct control option is inferior to the preferred approach. EPA requests comments on the validity of EPA’s concerns530

regarding this option and alternative methods for addressing those concerns. EPA modeling projects fewer emissions reductions under the Direct Control alternative than the proposed State Budgets/Limited Trading remedy. Additionally, the reductions would be achieved at a higher cost than the proposed remedy. See section V.E . for projected cos ts and emissions . A direct control program must account for outliers, e.g., units that can not install controls due to space limitations. EPA believes that the within
- the
- state company - wide averaging in the direct control alternative that EPA is taking comment on likely mitigates this concern. However, this averaging approach may put an owner with a small number of units within a state at a disadvantage compared to an owner with a larger number of units. EPA requests comment on this issue. Within the dire ct control approach EPA is taking comment on, the assurance provisions (which limit a company’s emissions within a state to its share of the budget with the variability limit if the state ’s budget with variability limit is exceeded) may also put an owner
w ith a small number of units at a disadvantage compared to531

an owner with a larger number of units within a state. EPA seeks comment on this issue. A direct control program based on emission rate limits does not cap annual emissions; i f there is growth in f ossil generation within a state, a rate
-based approach alone
c ould allow emissions increases . In the direct control approach for which EPA requests comment, the assurance provisions provide some assurance of achieving required reductions. Notably, the direct control approach described herein restricts compliance options more than a trading approach. EPA generally believes that granting more flexibility to companies in meeting an emissions reduction goal results in the ability of those companies to meet that goal at a lower cost and decreases reliability risks in the electric power system. While some portion of this effect is captured in IPM modeling ( see section V.E . for projected costs and emissions ), some types of unforeseen innovations in technology, fuel switching, and management cannot be captured by modeling. Any potential innovations and resulting cost savings are more likely to be found and utilized in the presence of regulatory flexibility. Based on historical experience, EPA believes that the benefits offered by a flexible trading approach are large and should532

be qualitatively appreciated, even if not quantified. Many of these benefits would be foregone under the direct control approach. E. Projected Costs and Emissions for Each Remedy Option Emission and cost projections for the three remedies discussed previously come from the Integrated Planning Model (IPM), a dynamic linear programming model of electric generation in the contiguous U.S . For each remedy, projected costs relative to the bas e case appear in Table V.E - 1 . The following section explains these projections in light of how the remedies differ and how they were represented in the model. The emissions projections below comprise fossil generation above 25 megawatts of capacity, the units that would be subject to the rule. More detail on the modeling of costs and emissions can be found in the Regulatory Impact Analysis for the proposed Transport Rule and in the EGMTSD . Table V.E - 1 – Projected Incremental Costs Due to Transport Rule Remedies Compared to Baseline without Transport Rule

or CAIR (billion 2006 dollars) 2012 2014 2020 2025 Limited Interstate Trading (proposed) 3.7 2.8 2.0 2.0 Intrastate Trading 4.2 2.7 2.2 2.2 Direct Control 4.3 3.4 2.5 2.3 1. State Budgets/Limited Tr ading533 The proposed remedy of State Budgets/Limited Trading was modeled with regional emissions cap s beginning in 2012 and state
- specific emissions limits beginning in 2014. The state - specific emissions limits represent state budgets plus 3
- year average variability limits . Because banking early reductions beyond the budget levels is allowed, 2012 SO 2 reductions are greater overall than state budgets alone would require in that year. Table V.E
- 2 shows the projected emissions reductions from this remedy. Table V.E - 2 – Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States with the Transport Rule Compared to Baseline without Transport Rule or CAIR (million tons )
2012 Base C ase Emissions 2012

Transport Rule Emissions 2012

Emi ssions Reductions 2014

Base C ase Emissions 2014

Transport Rule Emissions 2014

Emissions Reductions SO 2 8.4 3.4 5.0 7.2 2.6 4.6 Annual NO X 2.0 1.3 0.7 2.0 1.3 0.7 Ozone Season NO X 0.7 0.6 0.1 0.7 0.6 0.1
2. State Budgets/Intrastate Trading Though base d on the same state budgets as State Budgets/Limited trading, the alternative remedy of State Budgets/Intrastate Trading costs approximately 0.5 billion 2006 dollars more in 2012 and achieves slightly more SO 2534

reduction in 2012 (and slightly less in 2014), as Table V.E - 3 shows. In modeling this remedy, each state’s emissions were restricted to the state budget without variability. Without the opportunity for even limited trading of allowances across state borders, more banking was projected in some states . In other states, more immediate emissions reductions (relative to the base case) are projected so that state budgets are met exactly. Both of these factors drive 2012 costs higher than those of limited interstate trading and lead to slightly greater SO 2 reductions in 2012. Table V.E - 3 – Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States with the Intrastate Trading Alternative Remedy Compared to Baseline without

Transport Rule or CAIR (million tons)
2012 Base C ase Emi ssions 2012

Transport Rule Emissions 2012

Emissions Reductions 2014

Base C ase Emissions 2014

Transport Rule Emissions 2014

Emissions Reductions SO 2 8.4 3.2 5.2 7.2 2.7 4.5 Annual NO X 2.0 1.3 0.7 2.0 1.2 0.8 Ozone Season NO X 0.7 0.6 0.1 0.7 0.6 0.1

3. Direct Control The direct control alternative remedy consists of
source - specific emission rate limits commensurate with those used in the derivation of state budgets ( see sections535

IV.D and IV.E). To represent assurance provisions, the emissions from each state were also constrained to the state’s budget plus 3
- year average variability limit beginning in 2012. For states with more stringent SO 2 budgets in 2014, FGD retrofits were required on units shown to have cost
- effective retrofit opportunities at $2 ,000 per ton. Compared to the proposed remedy of State Budgets/Limited Trading, the direct control alternative costs approximately 0.6 billion 2006 dollars more and results in less SO 2 reduction in 2012, as shown in Table V.E - 4. Unlike remedies allowing b anking for early reductions, the direct control alternative does not result in reductions below state budgets in 2012. At the same time, meeting specific rate requirements for every source means there is little incentive to achieve additional reductions w ith fuel switching. Table V.E - 4 – Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States with the Direct Control Alternative Remedy Compared to Baseline without

Transport Rule or CAIR (million tons)
2012 Base C ase Emissions 2012

Transport Rule Emissions 2012

Emissions Reductions 2014

Base C ase Emissions 2014

Transport Rule Emissions 2014

Emissions Reductions536

SO 2 8.4 3.8 4.6 7.2 2.6 4.6 Annual NO X 2.0 1.3 0.7 2.0 1.2 0.8 Ozone Season NO X 0.7 0.6 0.1 0.7 0.6 0.1

4. State
- level Emissions P rojections Tables V.E
- 5, V.E
- 6, and V.E
- 7 show projected emissions at the state level from all EGUs in 2014. Table V.E - 5 – Projected State - level 101 SO2 Emissions from

Electric Generating Units in 2014 (Tons)

Base Case State

Budgets/ Limited Trading State

Budgets/ Intrastate Trading Direct

Control Alabama 322,362 172,430 162,103 172,430 Connecticut 6,160 3,234 3,208 3,208 Delaware 8,079 9,185 8,974 9,110 District of Columbia 176 179 180 180 Florida 194,723 139,805 159,120 135,366 Georgi a 173,257 92,375 89,706 92,375 Illinois 200,484 164,741 156,049 163,902 Indiana 804,425 240,730 267,564 239,852 Iowa 163,966 102,419 102,096 106,569 Kansas 65,125 51,248 52,501 53,275 Kentucky 739,595 123,837 128,318 123,833 Louisiana 94,866 94,933 9 2,647 96,390 Maryland 45,294 45,449 45,304 45,752 Massachusetts 17,265 10,306 8,595 8,909 Michigan 275,961 173,828 188,796 172,986 Minnesota 62,033 49,413 49,836 58,925 Missouri 500,649 192,645 190,815 190,532 Nebraska 115,695 75,095 73,219 75,061 New Jersey 39,721 16,562 14,935 16,569
101 The modeling presented in Tables V.E
- 5, V.E
- 6, and V.E
- 7 differs from the proposed Transport Rule because the District of Columbia (DC) is included neither in the annual SO 2 and NOX requirements nor in the ozone season NO X requirement. Modeled units in DC i nclude two small facilities, one of which has only units below 25 MW capacity. EPA believes the addition of emissions limits in DC would have little to no effect on the modeling results.537

New York 142,762 58,455 53,373 58,455 North Carolina 140,924 97,262 109,385 97,262 Ohio 841,199 232,964 269,547 228,514 Pennsylvania 974,644 154,852 183,276 154,855 South Carolina 156,200 131,232 123,525 131,232 Tennessee 600,071 106,767 100,012 94,078 Virginia 136,573 58,329 51,633 58,330 West Virginia 496,307 127,646 147,580 127,646 Wisconsin 117,397 85,933 87,328 83,709
Table V.E - 6 – Projected State - level Annual NOX Emissions from Electric Generating Units in 2014 (Tons)

Base Case State

Budgets/ Limited Trading State

Budgets/ Intrastate Trading Direct

Control Alabama 118,955 61,793 61,618 61,865 Connecticut 7,991 8,003 7,986 8,004 Delaware 5,790 6,176 6,126 6,074 District of Columbia 933 946 948 948 F lorida 196,373 126,155 126,065 94,646 Georgia 48,267 44,461 44,462 44,611 Illinois 80,451 57,589 54,773 57,949 Indiana 201,027 112,502 112,721 108,675 Iowa 68,259 53,072 50,146 52,069 Kansas 79,018 40,020 40,074 39,558 Kentucky 148,551 71,371 71,692 69,882 Louisiana 45,551 37,255 36,594 37,164 Maryland 36,089 36,326 33,778 36,532 Massachusetts 12,650 13,047 12,219 13,064 Michigan 98,941 65,066 65,973 67,525 Minnesota 55,283 38,969 39,114 38,039 Missouri 83,019 67,475 61,679 67,648 Nebraska 53,0 29 35,101 34,105 35,457 New Jersey 27,127 23,377 23,358 23,338 New York 36,352 36,592 34,538 36,597 North Carolina 62,608 60,516 54,639 60,517 Ohio 164,947 99,358 95,997 100,886 Pennsylvania 204,950 123,629 123,095 123,409 South Carolina 47,742 34,73 5 33,781 34,616 Tennessee 68,914 28,212 26,874 28,873 Virginia 37,485 35,805 35,745 37,004 West Virginia 100,095 48,180 48,987 50,555 Wisconsin 54,515 41,875 42,498 42,450538 Table V.E - 7 – Projected State - level Ozone - season NOX Emissions from Electric Generating Units in 2014 (Tons)

Base Case State

Budgets/ Limited Trading State

Budgets/ Intrastate Trading Direct

Control Alabama 26,995 26,727 26,552 26,823 Arkansas 21,667 12,080 12,095 12,077 Connecticut 3,446 3,453 3,446 3,446 Delaware 2,367 2,66 9 2,671 2,613 District of Columbia 391 397 397 398 Florida 94,686 62,221 62,037 48,170 Georgia 21,947 19,686 19,688 19,749 Illinois 24,167 24,930 22,833 24,701 Indiana 49,023 47,477 47,813 45,589 Kansas 34,537 17,470 17,590 17,282 Kentucky 29,927 29 ,376 29,671 29,107 Louisiana 21,443 17,388 17,106 17,308 Maryland 15,307 15,454 14,275 15,512 Michigan 29,934 27,778 28,052 29,415 Mississippi 16,955 8,524 8,526 8,522 New Jersey 10,470 10,324 10,295 10,260 New York 17,257 17,493 16,518 17,491 North Carolina 27,018 26,117 23,459 26,004 Ohio 44,753 41,141 40,051 42,789 Oklahoma 38,546 24,471 24,471 24,426 Pennsylvania 53,263 53,102 52,692 52,586 South Carolina 15,730 14,818 14,666 14,753 Tennessee 12,021 11,868 10,955 12,007 Texas 79,572 68,769 68,874 67,832 Virginia 16,264 15,397 15,289 16,093 West Virginia 24,339 20,249 21,466 21,500
F . Transition from the CAIR C ap - and
- T rade P rograms to P roposed P rograms This proposed Transport Rule would replace the CAIR rule and its associated trading pro grams. This section elaborates on some of the areas of the CAIR program that would need to be addressed in the transition to the new program. EPA is taking comment on how the transition would
occur.539

1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs The CA IR, CAIR SIPs, and CAIR FIPs would be replaced entirely by the Transport Rule provisions. If this proposed Transport Rule is finalized in 2011, the CAIR, CAIR SIPs, and CAIR FIPs would sunset at the completion of all 2011 control period activities. In o rder to implement the sunsetting of the CAIR and CAIR FIPs, the proposed rule includes several revisions of the CAIR, §§ 51.123 and 51.124, and the CAIR FIPs, §§ 52.35 and 52.36. First, sunsetting the CAIR and CAIR FIPs in 2011 would mean that the requireme nts of the CAIR and CAIR FIPs would not apply to control periods after 2011. Specifically, the CAIR would be revised to rescind, with regard to any control period beginning after December 31, 2011, the findings that States must revise their SIPs to meet CAIR requirements. Similarly, the CAIR FIPs would be revised to state that, with regard to any post
- December 31, 2011 control period, CAIR FIP requirements would not be applicable. Second, the sunsetting in 2011 would mean that the CAIR trading programs would not continue past 2011. Consequently, the proposed revisions of the CAIR and CAIR FIPs would state that, with regard to any post
- December 31, 2011 control period, the Administrator would not carry out540

any of the functions established for the Adminis trator in the CAIR model trading rule, the CAIR FIPs, or any state trading programs approved under the CAIR. Third, the sunsetting in 2011 would mean that CAIR allowances allocated for control periods after 2011
-- which have already been recorded by the Administrator in the Allowance Management System compliance accounts of sources in many states
-- would not be usable in the CAIR trading programs for control periods ending before 2012. Specifically, under the existing CAIR trading programs, a source th at fails to hold sufficient allowances to cover emissions for the 2011 control period (whether annual or ozone season) must provide for surrender to the Administrator three allowances (one as an offset and two as an automatic penalty) allocated for the 201 2 control period for every one allowance that was not held as required. However, consistent with the proposed termination of the CAIR trading programs for control periods after 2011, EPA believes that allowances allocated for such control periods (e.g., 2 012 allowances) should not be usable for any purpose. In any event, because such allowances would have little or no market value, their deduction would impose little or no cost on the party holding them. Consequently, the proposed revisions of the CAIR a nd CAIR FIPs would541

state that the Administrator would not deduct, for excess emissions, any CAIR allowances allocated for control periods in 2012 or any year thereafter. These revisions would ensure that no CAIR allowances allocated for post
2011 control periods would be used as an offset of, or an automatic penalty for, excess emissions. As a result of these proposed revisions of the CAIR and CAIR FIP rules, there would be no offset or automatic penalty deducted for a source that failed to hold sufficient allowances to cover its 2011 control period emissions unless the state SIPs are revised. In order to preserve the deductions for offsets and automatic penalties for 2011 control periods, the CAIR SIPs for most states (i.e., 20 out of the 28 states subjec t to at least one CAIR trading program) would need to be modified and the modified CAIR SIPs would need to be approved by the EPA

– - before EPA conducts the process of determining source compliance after the allowance transfer deadline for the 2011 control period s – - in order to change the allocation year of the allowances required to be deducted (e.g., from allowances allocated for 2012 to allowances allocated for 2011). Although EPA’s past experience with trading programs strongly suggests that few sourc es would be out of compliance with the requirement to hold allowances covering542

2011 emissions, all of these CAIR SIPs would have to be revised because there is no way to predict which few sources in which few states might be out of compliance in 2011 and t he process of revising SIPs is too long to be started while EPA is still determining compliance. In fact, when states needed to revise their SIPs to include the existing requirements of CAIR and submit the revised SIPS to the Administrator, EPA found that states needed up to 3 years to develop and submit SIP revisions, and EPA needed about 6 months to act on the SIP revisions. In light of this experience with SIP revisions under CAIR, EPA believes that it would highly unlikely that all, or even most, stat e CAIR SIPs could be revised, submitted, and approved in time

– - even if the SIP revision process were started when a final Transport Rule is promulgated
-- to change what allowances were to be used for offsets and automatic penalties for excess emissions for the 2011 control periods. Moreover, any excess emissions for the 2011 control periods would be violations of the state SIPs (or of CAIR FIPs in those states with CAIR FIPs) and of the Clean Air Act and, therefore would be subject to discretionary civ il penalties under CAA Section 113. Each ton of excess emissions, and each day in the control period involved543

(i.e., 365 days for annual control periods and 153 days for the ozone season control period), would be a violation, with a maximum penalty of $25 ,000 (inflation adjusted to $37,500) per violation. In determining what level of discretionary civil penalties to impose on a source that has excess emissions violations, EPA routinely considers, among other things, whether, and if so what level of, other penalties (e.g., automatic excess emissions penalties) have already been imposed for the same violations, as well as any economic benefit of noncompliance (e.g., the avoidance of the cost of surrendering allowances to cover emissions). See, e.g., 42 U.S. C. 7413(e)(1) (including, as penalty assessment criteria, “payment by the violator of penalties previously assessed for the same violation” and “the economic benefit of noncompliance”). Consequently, EPA believes that, regarding the CAIR 2011 control per iods (both annual and ozone season) for which it is not feasible to change the offset and automatic penalty provisions to make them workable, the potential for assessment of significant, discretionary civil penalties would provide a strong incentive for compliance with the allowance
- holding requirement and avoidance of excess emissions. In addition to the previously
- described, proposed revisions to §§51.123, 51.124, 52.35, and 52.36, certain544

provisions in Part 52 that reflect, state by state, the CAIR SIP revisions and CAIR FIP requirements applicable to each state would need to be revised to implement the sunsetting of the CAIR, CAIR SIPs, and CAIR FIPs. However, the timing for proposal and adoption of revisions to Part 52 is necessarily different for the Part 52 provisions addressing CAIR SIP revisions and those addressing revisions of the CAIR and the CAIR FIPs themselves. The Part 52 provisions addressing CAIR SIP revisions for the individual states reflect EPA’s approval of CAIR SIP revisions adopted and submitted to EPA by the respective states. The first step toward sunsetting those Part 52 provisions would be that, if and after the proposed Transport Rule was finalized, the respective states would change their SIPs in order to, among other things, make the CAIR provisions in the SIPs inapplicable to any control period that starts after December 31, 2011. After the submittal by the respective states of these SIP revisions, EPA would review and approve such changes. Consequently, the rule text appr oving such CAIR SIP revisions would not be included in either the proposed Transport Rule or any final rule based on the proposed Transport Rule, but rather would be proposed and adopted only after the respective states revised their SIPs. As EPA did when transitioning545

from the NO X Budget Trading Program to the CAIR NO X ozone season trading program, EPA will work with states to transition from state CAIR programs to their replacement FIPs or state SIPs. This assistance will be provided through meetings or workshops, web
-based references, one
on - one assistance through the EPA regions, etc. In contrast, the Part 52 provisions adopting CAIR FIPs for individual states could be revised, as part of the proposed Transport Rule, to sunset these CAIR FIPs because
n o state action would be required to accomplish this sunsetting. EPA proposes to revise each state
- specific Part 52 provision adopting a CAIR FIP
-- whether for NO X annual or ozone season emissions or SO 2 emissions
-- to add a paragraph stating that: with regard to any control period starting after December 31, 2011, the respective CAIR FIP would not apply and the Administrator would not carry out any of the functions set forth for the Administrator in the trading program rules under the CAIR FIP; and the Administrator would not deduct for excess emissions any CAIR allowances allocated for 2012 or any year thereafter. The new, added rule text would be very similar to the proposed rule text revisions to §§52.35 and 52.36 and would be essentially the same for each of these state
- specific Part 52 provisions. EPA has included in the proposed546

Transport Rule the proposed rule text making these state
by
- state revisions for Delaware, District of Columbia, Indiana, Louisiana, Michigan, New Jersey, Tennessee, Texas, and Wisconsin. These provisions revise all of the state
specific Part 52 provisions adopting CAIR FIPs provisions to make the CAIR FIPs inapplicable to any control period that starts after December 31, 2011 and state that the Administrator would not carry out any functions under the CAIR trading programs during any such control period and would not use any CAIR allowances allocated for any such control period. 2. Change in States Covered The states covered by the proposed Transport Rule differ slightly from states covered by the CAIR. Namely, as compared with the states covered by the CAIR NO X ozone season trading program, the states covered by the proposed Transport Rule NO X ozone season trading program would include Georgia, Kansas, Oklahoma, and Tex as and would not include Iowa, Massachusetts, Missouri, and Wisconsin. Further, as compared with the states covered by the CAIR NO X annual and SO 2 trading programs, the states covered by the proposed Transport Rule NO X Annual and SO 2 trading programs woul d include Connecticut, Kansas, Massachusetts, Minnesota, and Nebraska and would not include Mississippi547

and Texas. ( See also the discussion in section IV.D. regarding the possibility that the states to which this rule would apply could expand.) Conseque ntly, sources in some states that would be covered by the proposed Transport Rule would have new allowance holding requirements beginning in 2012, but would not have been subject to the CAIR trading programs. Conversely, sources in some states covered by the CAIR or CAIR FIPs would not be subject to the proposed Transport Rule. To the extent that the CAIR reductions were needed or relied upon to satisfy other SIP requirements, states might need to find alternative ways to satisfy requirements for their SI Ps. EPA will work with individual states to identify state
- specific options to ensure that necessary reductions needed for other SIP requirements can continue. 3. Applicability, CAIR Opt
- ins and NO X SIP Call Units Except for the changes in the states covered, the general applicability provisions of the proposed Transport Rule would be essentially the same as the CAIR general applicability provisions, with a few exceptions. First, the proposed Transport Rule does not allow any units to opt into the tradin g programs. In contrast, under CAIR, states could elect to allow boilers, combustion turbines, and other combustion devices to opt into the CAIR trading548

programs under opt
- in provisions specified by EPA, and a number of states adopted these opt
- in provisi ons. However, currently no units have opted into the CAIR trading programs, and, even in the Acid Rain Program, where opt
- in provisions have been in place since 1995, very few units have actually opted in. Second, under the CAIR trading programs, a sta te subject to the NO X SIP Call was allowed to expand the applicability of the CAIR NO X ozone season trading program in the state in order to include all units subject to the NOX Budget Trading Program (NBP) under the NO X SIP Call and thereby to continue to meet the state’s NO X SIP Call requirements. Fourteen states chose to expand the CAIR NO X ozone season applicability in this way, while six states chose not to expand the applicability and instead to meet their NO X SIP Call obligations in other ways. In expanding the applicability of the CAIR NO X ozone season trading program, the fourteen states brought into the program large industrial boilers and turbines (with maximum design heat input greater than 250 mmBtu/ hr) and, in some cases, smaller electric ge nerating units (serving generators with nameplate capacity of 15 through 25 MWe), and generally the CAIR NOX ozone season budgets in these states were increased to account for these additional sources. In contrast, the549

proposed Transport Rule NO X ozone se ason trading program would not allow for expansion of applicability to include these units currently covered only by the NBP. There are several factors underlying this difference between the proposed Transport Rule and the CAIR. First, in determining whi ch states are contributing significantly or interfering with maintenance of the ozone NAAQS, the Transport Rule does not cover some states subject to the NO X SIP Call (i.e., Massachusetts, Missouri, and Rhode Island). Further, the six states that chose un der the CAIR to require the necessary NO X SIP Call reductions through provisions other than the CAIR NO X ozone season program would not likely be interested in expanding applicability under the Transport Rule NO X ozone season trading program to cover these units. In addition, EPA has determined that these units as a group did not actually reduce emissions as a result of the NBP or through their inclusion in the CAIR NOX ozone season trading program. In fact, their current emission rates are nearly identic al to what they were before the NBP started. Moreover, these units as a group had allowances that they did not need for compliance and that were available for trading to other affected units. The Transport Rule, as proposed, does not include these units and does not include provisions for allowing states550

expand applicability to include them. EPA is taking comment on this approach. 4. Early Reduction Provisions Substantial emission reductions have occurred as a result of the CAIR programs. These reducti ons are greater than were expected when the rule was promulgated. This is evidenced in the banks of allowances that exist in each of the CAIR programs. a. SO 2 Allowance Bank The bank of Title IV allowances was more than 12 million tons at the end of 200 9. This bank is the result of emission reductions for Title IV where allowances are used for compliance with the requirement to hold allowances covering emissions and early reductions for the CAIR SO 2 trading program. EPA believes that it is advantageous to minimize sources’ use of the Title IV allowance bank if possible and recognizes that, if the bank has minimal future market value, there may be incentive to use as many banked allowances as possible. EPA tracks the SO 2 emissions on a quarterly basis and makes the information available to the public at http://epa.gov/airmarkets/quarterlytracking.html . EPA evaluated whether the Title IV allowance bank could be used in the proposed Transport Rule SO 2 program in551

any way. One idea presented to EPA was to distribute Transport Rule SO 2 allowances based on the number of Title IV allowances a source has in its bank at the completion of compliance in the last year of the CAIR SO 2 program, thereby incentivizing minimal use, by sources, of Title IV allowance ban ks and encouraging continued emission control. EPA is concerned that the approach would have significant legal risk because the number of Title IV allowances in a source’s account may not be directly related to the section 110(a)(2)(D)(i)(I) mandate to el iminate significant contribution . EPA chose instead, under the proposed Transport Rule, to distribute allowances in a manner directly linked to its calculation of each state’s significant contribution and interference with maintenance. EPA is confident t hat the approach selected is consistent with the Court’s opinion in North Carolina v. EPA , 531 F.3d 896, 922 (D.C. Cir. 2008) . ( Additional information on this approach can be found in the docket.) EPA requests comment
on whether or not an allowance distr ibution approach based on the number of Title IV allowances in a given source’s account would be consistent with the Court opinion . EPA proposes that the Transport Rule provisions not allow the use of Title IV allowances either as the basis for allocating Transport Rule SO 2 allowances or directly for552

compliance with allowance
- holding requirements . Thus, there would be no SO 2 allowances carried over into the new SO 2 program. Title IV allowances continue , of course, to be used for compliance with the Acid Rain Program. b. NOX Allowance Banks Assuming that NO X emissions in 2010 and 2011 are equal to what they were in 2009, the CAIR NO X ozone season bank would contain over 600,000 allowances (which would equal more than 100 percent of the total of the state bu dgets under the proposed Transport Rule NO X ozone season program for 2012), and the CAIR NO X annual bank would contain over 270,000 allowances (which would equal about 20 percent of the total of the state budgets under the proposed Transport Rule NOX annua l program for 2012), after completion of true
up of allowance holdings and emissions for 2011. Estimates of the size of the banks have only recently been made based on reported 2009 emissions data, and the impacts of different approaches to handling the b anks have not yet been modeled. However, EPA is concerned about the potential impacts of these approaches. On one hand, allowing pre
- 2012 CAIR NO X allowances and CAIR NO X ozone season allowances to be used in the proposed Transport Rule NOX programs, and thereby ensuring that the allowances would continue to have some market value in the future, would553

promote the continuation
-- in 2010 and 2011
-- of the reductions that occurred in 2009 under the CAIR NO X programs. On the other hand, the amounts of the banks are so large that they might significantly reduce the amount of emission reductions that would otherwise be achieved in the proposed Transport Rule NO X programs, particularly in the earlier years (e.g., 2012 and 2013). EPA has identified several p ossible approaches for handling banked pre
- 2012 CAIR NO X allowances in the Transport Rule NO X programs. The first approach might be to allow all such banked CAIR allowances to be brought into the Transport Rule NO X programs, make the assurance provisions effective starting in 2012, and rely on the assurance provisions to ensure that each state continues to eliminate all of the significant contribution and interference with maintenance that EPA has identified in today’s proposal . The banked CAIR allowances would be usable, and the assurance provisions would apply, in all states in the Transport Rule NO X programs. However, EPA is concerned about the legal risk of this approach. Specifically, this approach might be viewed as having the effect of allowing sou rces that were advantaged by the development of state budgets using fuel adjustment factors

– - the use of which was reversed by the Court in North554

Carolina , 531 F.3d at 918
- 21

– - and that still hold part of their allocated allowances to continue have an advantage in the Transport Rule NO X trading programs . The second approach might be to allow only a limited amount of banked pre
- 2012 CAIR allowances to be brought into the Transport Rule programs. This could be accomplished by allowing all such banked all owances to be used, but at a tonnage authorization level significantly lower than one ton per allowance, in the Transport Rule NO X programs. However, while severely limiting the tonnage authorization of banked allowances that is allowed into the new progr ams would limit any advantage realized by sources that received fuel
- adjustment
- factor
-based CAIR allowance allocations, this would also limit any beneficial impact that bringing CAIR allowances into the new programs might have on preserving emission reduc tions in 2010 and 2011. The third option might be to try to factor the bank into the calculation of state budgets by reducing the state budgets to take account of the banked pre
- 2012 CAIR allowances. This might allow these allowances to be used in the T ransport Rule NO X programs without adversely affecting the states’ elimination of the part of significant contribution and interference with maintenance that EPA has identified . However, this approach would not555

be feasible because EPA cannot determine in advance in which states banked pre
- 2012 CAIR allowances might be used and so would not know which state budgets should be adjusted and what amount of adjustment would be necessary. A final approach would simply be to not allow the use of any banked pre
- 2 012 CAIR allowances in the Transport Rule NOX programs. This approach would avoid the potential legal and practical problems raised by the other approaches and is the approach proposed by EPA. EPA requests comment on the proposed approach, the previously
- discussed alternative approaches, and any other possible approaches for handling banked pre
- 2012 CAIR allowances in the Transport Rule NO X programs. 5. Source Monitoring and Reporting Monitoring and reporting using 40 CFR Part 75 provisions is required f or all units subject to the CAIR programs and would also be required for all units subject to the proposed Transport Rule programs. In states covered by both the CAIR and the proposed Transport Rule, units would generally have no changes to their monitori ng and reporting requirements and would continue to monitor and submit reports as they have under the CAIR. The exceptions are units in: CAIR states subject to CAIR NOX ozone season requirements but NO X and SO 2 annual requirements under the556

proposed Trans port Rule; or CAIR states subject to CAIR NO X annual and ozone season and SO 2 requirements but only to NOX ozone season requirements under the proposed Transport Rule. These exceptions could arise, in part, because under 40 CFR Part 75 some units (i.e., n on -Acid Rain units) that are in NO X ozone s eason, and not NO X annual, programs have the option of monitoring and reporting NO X emissions for just the ozone season. Units in the following states monitor and report both SO 2 and NOX year - round under the CAIR and would continue to do so under the Transport Rule: Alabama, Delaware, the District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Sou th Carolina, Tennessee, Virginia, West Virginia, and Wisconsin. Non
-Acid Rain units in Arkansas are currently required to monitor and report NO X in the ozone season under the CAIR and would continue to be required to do so under the proposed Transport Rul e. Non -Acid Rain units in Connecticut and Massachusetts (about 15 units total ) that currently monitor and report NO X in the ozone season would need to monitor and report NO X and SO 2 on an annual basis under the proposed Transport Rule.557 Non -Acid Rain units in Mississippi (about 4 units) and Texas (about 52 units) are currently monitoring and reporting NO X and SO 2 year - round and under the proposed Transport Rule would be required to monitor and report NO X in the ozone season. (All of these units burn natura l gas and emitted approximately 12 tons of SO 2 in 2009.) In states not covered by the CAIR but covered by the proposed Transport Rule, some units would have to meet new monitoring and reporting requirements under 40 CFR Part 75. Kansas, Minnesota, and Neb raska are not covered by the CAIR and are covered by the Transport Rule, and units there would need to monitor and report NO X and SO 2 emissions year
round. Oklahoma is not covered by the CAIR and is covered by the Transport Rule, and units there would nee d to monitor and report NO X in the ozone season. There are about 34 non
-Acid Rain units total in Kansas, Nebraska and Oklahoma not monitoring and reporting under 40 CFR Part 75 that would need to begin to do so. Most of these units are simple
- cycle combu stion turbines used in the ozone season as peaking units and would likely be able to utilize the Low Mass Emissions or Appendix D and E methodologies in 40 CFR Part 75, which do not require a continuous emissions monitoring system (CEMS). The circulating fluidized bed (CFB) units in Oklahoma (about 4 units) that burn coal are558

already monitoring and reporting under 40 CFR P art 60, subpart Da, which requires an SO 2 , NOX and CO 2 /O 2 (diluent) CEMS. These boilers would only have to add a flow monitor and upgra de the automated data acquisition and handling system. Non -Acid Rain units in Minnesota (about 20 units) would also need to monitor and report, but were already doing so under the CAIR before the CAIR was stayed in Minnesota (74 FR 56721, November 3, 2009 ); therefore, they would simply have to reactivate those monitoring systems. Units that h ave not been covered by 40 CFR P art 75 monitoring and reporting in the past would likely have less than one year to install, certify, and operate the required monitori ng systems. EPA believes that these units would reasonably be able to comply with this requirement because the monitoring equipment needed is not extensive or is largely in place already for the purpose of meeting other requirements. Quality assurance an d reporting provisions and data system upgrades may be necessary, but there would be sufficient time to accomplish this. G. Interactions with existing Title IV Program and NO X SIP Call 1. Title IV Interactions Promulgation of a Transport Rule would not a ffect any Acid Rain Program requirements. Any Title IV sources that559

are subject to final Transport Rule provisions would still need to continue to comply with all Acid Rain provisions. Acid Rain requirements are established independently in Title IV of t he Clean Air Act and would not be replaced by the Transport Rule. In contrast with the CAIR, the proposed Transport Rule would not allow Title IV SO 2 allowances to be used in the Transport Rule program. Similarly, Transport Rule SO 2 allowances would not be useable in the Acid Rain Program. Title IV SO 2 and NOX requirements will continue to apply independently of the Transport Rule provisions. The Transport Rule program as proposed has no opt
- in provisions, so no sources , including any that have opted in to the Acid Rain program would be able to opt
- in to the Transport Rule program. Compliance with the Transport Rule would reduce SO 2 emissions in the Transport Rule states below the 2010 Title IV cap. So, as sources compl ied with the Transport Rule, emissi ons would go down and with them so would the demand for Title IV allowances. Therefore, the Title IV allowance prices are expected to be very low once the Transport Rule is finalized; some analysts suggest a price of near ly zero. Acid Rain sources will s till be required to comply with Title IV requirements, including the requirement to hold560

Title IV allowances to cover emissions at the end of a compliance year. There would likely be changes to emissions at some Acid Rain sources outside of the Transport Rule area as a result of the transition from CAIR to the Transport Rule. Namely, emissions at some non
- Transport Rule Acid Rain sources may increase because of the change in the Title IV allowance price. This would be expected to occur mainly in the state s that border the Transport Rule states. Overall, SO 2 emissions from these non
- Transport Rule Acid Rain
sources would be expected to increase approximately 237,000 tons each year if the Transport Rule is implemented compared to what they would have been i n the absence of the Transport Rule. There is more discussion of this effect in section IV.D. 2. NOX SIP Call Interactions States affected by both the NOX SIP Call and any final Transport Rule will be required to comply with the requirements of both rule s . The Transport Rule does not preempt or replace the requirements of the NO X SIP Call. However, the proposed Transport Rule ozone season program would achieve the emissions reductions required by the NO X SIP Call from EGUs greater than 25 MW in nearly a ll NOX SIP Call states. The NOX SIP Call states used the NOX Budget561

Trading Program (NBP) to comply with the NO X SIP Call requirements for EGUs greater than 25 MW and large non
- EGUs with a maximum rated heat input capacity greater than 250 MMBTU/hr. (In some states, EGUs smaller than 25 MW were also part of the NBP as a carryover from the Ozone Transport Commission NO X Budget Trading Program.) EPA stopped administering the NBP after the 2008 ozone season control period activities , and states used another mechanism to comply with the NO X SIP Call requirements. Many of the states using the NBP used the CAIR NO X ozone season trading program to replace the NBP. T o address NO X SIP Call requirements , f ourteen NO X SIP Call states chose to expand the CAIR NO X oz one season applicability to include all NBP
- affected units . EPA has analyzed the effect of allowing states to expand their CAIR NOX ozone season applicability and consequently their CAIR NOX ozone season budgets to include the additional non - CAIR affected NBP units . In 2009, the additional units emitted about half of the amount of allowances added to the CAIR NO X ozone season budgets for them. The remaining allowances are available for the sources to trade to other affected units. As a group, these unit s did not reduce their NO X emissions or their NO X emission rates as a result of their inclusion in the CAIR NO X ozone season program. If EPA were562

to allow them to be part of the Transport Rule NO X Ozone Season Program, and if states were allowed to increa se the Transport Rule NO X Ozone Season Budgets by the amounts allowed under the NBP and CAIR for these unit s, a state’s ability to eliminate the part of significant contribution and interference with maintenance that EPA has identified in today’s proposal could be jeopardized. One option considered that could possibly address concerns about still being able to address significant contribution and interference with maintenance would be to require the budget increase to be much less than allowed under the NB P and CAIR. For example, the unit s ’ 2009 emissions (or 2012 projected emissions if they are required to install controls for another program) could be used to determine the budget increase and the elimination of emissions causing significant contribution and interference with maintenance might be able to be preserved. It is likely the budget changes would not be consistent across states as each state’s impact would have to be considered individually. EPA is proposing to not allow the expansion of the app licability of the Transport Rule. Therefore, the NBP states would need to achieve their NOX SIP Call emission reductions another way in order to continue to comply with the NO X SIP Call. If EPA563

promulgates a final rule that does not allow the expansion of the Transport Rule to NBP unit s, any state that allowed these unit s to participate in the CAIR NO X Ozone Season Program would need to submit a SIP revision to address their NO X SIP Call requirement for the reductions. States that were part of the CAIR NO X ozone season program or the NBP that are not part of a final Transport Rule ozone season program would need to submit SIP revisions that address the NO X SIP Call requirements for any emission reductions that were part of either the CAIR NO X ozone season program or the NBP and would not continue to be addressed some other way. EPA will work with states to ensure that NO X SIP Call obligations continue to be met. VI. Stakeholder Outreach In early 2009, EPA began its efforts to coordinate activities with sta te regulatory partners and other stakeholders on the new transport rule to replace CAIR. To establish open lines of communication and ensure transparency in the regulatory process, EPA participated in a series of “listening sessions” in March and April, 2 009 with states, nongovernmental organizations, and industry. EPA also participated in tribal teleconferences. The same agenda was set for each of the ten meetings. Meeting notes were developed and distributed for concurrence and to564

assure accuracy. Subsequent to these sessions, EPA received post
-meeting comments and additional detailed suggestions and analyses on ways to address some of the issues that the court cited, most notably from state regional organizations in the eastern U . S. All the stakehol der
- related materials may be found in the EPA docket for the transport rule (OAR
- 2009
- 0491). Following the remand of CAIR to EPA in December 2008, 17 states in the East and Midwest, under the umbrellas of the OTC and Lake Michigan Air Directors Consortium (LADCO) with support from southeastern states, worked to develop recommendations for EPA to consider in crafting a new transport rule to replace CAIR. The comprehensive framework presented the consensus approach the states reached but noted that certain regional differences would be addressed in separate letters with additional recommendations and supporting materials. EPA h as considered and appreciates all the ideas and recommendations provided by the states. We are employing the technical work that they submitted as part of the data set we are using in this and later transport rules. Topics addressed in the listening sessions, where EPA asked stakeholders and regulatory partners for their thoughts on particular issues, included:565

 Analysis and baseline s

 Linkages between a state’s significant contribution and downwind nonattainment/interference with maintenance

 Remedies

 Attainment planning

 Other areas EPA continued to provide updates to regulatory partners and stakeholders through monthly conference cal ls with states, hosted by, e.g., NACAA, as well as industry and NGO conferences where EPA directors often made presentations. Several of the options presented in this proposal were influenced by feedback received from stakeholders and regulatory partners, including:

• 2012 baseline used in the calculation of each state’s significant contribution and interference with maintenance

• The “tiered” approach to SO 2 emissions reductions requirements

• Threshold (1 percent of the NAAQS) used for linking upwind areas to downwind nonattainment and maintenance receptors566

• Approach used to give independent meaning to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I)

• Level of reductions required

• Use of limited interstate trading

• Correlated and coordinated requirements and timing for the power industry EPA looks forward to the public comment period of this rulemaking and is committed to establishing and maintaining close working relationships with a broad range of public and private sector organizations. VII. S tate Implementation Plan Submissions A. Section 110 (a)(2)(D)(i) SIPs for the 1997 Ozone and PM2.5 NAAQS All states have an obligation to submit SIPs that address the requirements of CAA section 110(a) ( 2) within 3 years of promulgation or revision of a NAAQS. With respect to the 1997 ozone and PM2.5 NAAQS , EPA found in 2005 that states had failed to make submissions that address the requirements of section 110(a)(2)(D)(i) related to interstate transport of pollution. See 70 FR 21147 (April 25, 2005). Als o in 2005, EPA promulgated the CAIR, which was intended to provide states covered by the rule with a mechanism to satisfy their section 110(a)(2)(D)(i)(I)567

obligations. In the CAIR, EPA concluded that the States in the CAIR region would meet their section 110(a)(2)(D)(i) obligations to address “significant contribution” and “ interference with maintenance” requirements by complying with the CAIR requirements. Consequently, states within the CAIR region did not need to submit a separate SIP revision to sati sfy the section 110(a)(2)(D)(i) requirements provided they submitted a SIP revision to satisfy CAIR. Most of the CAIR states participated in the CAIR trading programs and submitted SIP revisions that EPA subsequently approved. In 2008, the Court granted several petitions for the review of the CAIR and found, among other things, that EPA had not demonstrated that the CAIR effectuates the statutory mandate of section 110(a)(2)(D)(i)(I). The EPA approvals of the CAIR SIPS preceded the remand of the CAIR by the Court. Therefore, because the D.C. Circuit Court found CAIR and the CAIR FIPs unlawful , EPA’s approval of the provisions of a state’s SIP submittal as addressing the requirements of the CAIR could not satisfy that state’s section 110(a)(2)(D)(i)(I) ob ligation. In other words, a CAIR SIP submission can no longer be considered an adequate section 110(a)(2)(D)(i)(I) SIP submission. For this reason, EPA’s 2005 findings that states had failed to submit SIPs that satisfy section568

110(a)(2)(D)(i)(I) 102 remain in force regardless of whether a state covered by the CAIR submitted and/or had an approved SIP stating that compliance with the CAIR satisfied their 110(a)(2)(D)(i) obligations. The 2005 findings of failure to submit also remain in force for many states not covered by the original CAIR. Some of these states have not yet submitted 110(a)(2)(D)(i)(I) SIPs and thus the findings remain in force. However, several states that were not covered by the CAIR have since 2005 submitted SIP revisions to satisfy the requirements of section 110(a)(2)(D)(i) for the 1997 8
- hour ozone and PM2.5 NAAQS. Some of these SIPs have been approved and some are pending approval. For the states that have now been identified to be contributing significantly to nonattainment or inte rfering with maintenance under this proposed rule and whose 110(a)(2)(D)(i)(I) SIPs with respect to the 1997 ozone and PM2.5 NAAQS are pending approval, EPA will finalize the FIP included in this proposed rule only if EPA either determines that the SIP submission is incomplete or

102 The 2005 findings of failure to submit related to state’s obligati ons pursuant to section 110(a)(2)(D)(i). The CAIR, however, addressed only the requirements of 110(a)(2)(D)(i)(I). The remand of CAIR, therefore, had no impact on state SIP submissions or EPA approval of state SIP submissions pursuant to section 110(a)(2 )(D)(i)(II).569

disapproves the SIP submission. (Alternatively, if a state withdraws its SIP submission, EPA will finalize the FIP.) For states which are not included in a final FIP under this proposed transport rule and that have not submitted a 110(a)(2)(D)(i)(I) SIP to address the 1997 ozone and PM2.5 NAAQS, a SIP submittal is required. EPA has approved the 110(a)(2)(D)(i) submission from the state of Kansas for the 1997 ozone and PM2.5 NAAQS. The updated modeling done for this proposed rule demonstrates that emissions from Kansas significantly contribute to nonattainment or interfere with maintenance of the 1997 8
- hour ozone NAAQS in downwind areas. Because Kansas’ current SIP does not prohibit these emissions, it is not adequate to satisfy the requirements of 110(a)(2)(D)(i)(I) at this time. For Kansas, under a separate action, EPA plans to propose a finding under CAA 110(k)(5) (known as a SIP Call) that the state’s existing SIP is substantially inadequate to meet the requirements of 110(a) (2)(D)(i)(I) with respect to the 1997 ozone NAAQS. That SIP c all, if finalized, would also establish a deadline for submission of a new 110(a)(2)(D) (i)(I) SIP which EPA would review for completeness . Therefore, i n today's notice EPA is proposing to final ize the FIP for Kansas for ozone only if570

the state fail s to submit a complete and approvable SIP by the deadline established in any final SIP Call. B. Section 110 (a)(2)(D)(i) SIPs for the 2006 24
- hour PM2.5 NAAQSWith respect to the 2006 24
- hour PM2.5 NAAQS , EPA has issued a separate federal register notice f inding that a number of states failed to make the required 110(a)(2)(D)(i)(I) SIP submissions. None of the SIP submittals in the states that have submitted section 110(a)(2)(D) (i)(I) transport SI Ps fo r the 2006 24
- hour PM2.5 NAAQS have been acted on yet by EPA. For the states with SIPs that are pending approval, EPA is proposing to finalize the FIP with respect to the 2006 PM2.5 NAAQS only if EPA finds the previously submitted SIP incomplete or disapp roves the SIP submission. Alternatively, if any of these states withdraws its 2006 24
- hour PM2.5 SIP submittal, EPA plans to issue a separate notice of finding for such states. C. Transport Rule SIPs EPA also notes that, by promulgating this Transport Ru le FIP, EPA is in no way affecting the right of s tates to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. The SIP must provide adequate provisions to prohibit NOX and571

SO 2 emissions that con tribute significantly to nonattainment or interfere with maintenance in another state or states . EPA is taking comment on how a state could replace the FIP with a SIP and what the SIP approval criteria should be. VIII. Title V Permitting EPA’s proposed FIPs would not establish any permitting requirements independent of those under Title V of the CAA and the regulations implementing Title V, 40 CFR Parts 70 and 71 103 . Title V requires that sources meeting certain criteria have permits meeting the requireme nts specified in Title V and the Title V regulations. For example, for sources required to have Title V permits, such permits must include, among other things, all “applicable requirements,” as defined in the Title V regulations (40 CFR 70.2 and 71.2 (de finition of “applicable requirement”)). EPA anticipates that, given the nature of the units covered by the proposed FIPs, most of the sources at which they are located would be subject to Title V permitting requirements. For sources subject to Title V, the requirements applicable to them under the proposed FIPs would be "applicable requirements" under Title V and therefore would need to be included in the Title V permits.

103 Part 70 governs approved state Title V programs, and Part 71 governs the federal Title V program.572

For example, requirements under the proposed FIPs concerning designated representa tives, monitoring, reporting, and recordkeeping, the requirement to hold allowances covering emissions, the assurance provisions, and liability would be “applicable requirements” and necessary to include in the permits. The Title V permits program inclu des, among other things, provisions for permit applications, permit content, and permit revisions that would address the applicable requirements under the proposed FIPs in a manner that would provide the flexibility necessary to implement a market
based pr ogram such as the one that EPA is proposing. For example, the Title V regulations provide that a permit issued under Title V must include, for any “approved...emissions trading and other similar programs or processes” applicable to the source, a provision stating that no permit revision is required “for changes that are provided for in the permit.” 40 CFR 70.6(a)(8) and 71.6(a)(8). The trading program regulations for the proposed FIPs would include a provision stating that no permit revision is necessary for the allocation, holding, deduction, or transfer of allowances. Consistent with the Title V regulations, this provision would also be included in each Title V permit for a covered source. As a result,573

allowances could be traded (or allocated, held, o r deducted) under the FIPs without a revision of the Title V permit of any of the sources involved. As a further example of flexibility under Title V, the Title V regulations allow the use of the minor permit modification procedures for permit modificati ons “ involving the use of economic incentives, marketable permits, emissions trading, and other similar approaches, to the extent that such minor permit modification procedures are explicitly provided for in an applicable implementation plan or in applicab le requirements promulgated by EPA .” 40 CFR 70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B). The trading program regulations for the proposed FIPs would include provisions requiring unit owners and operators to submit monitoring system certification applicat ions (or, for alternative monitoring systems, petitions) to EPA establishing the monitoring and reporting approach to be used by the unit. These applications and petitions are subject to EPA review and approval to ensure consistency in monitoring and repo rting among all trading program participants. As provided in the proposed regulations, EPA would only allow use of approaches that would result in emissions data with an appropriate level of precision, reliability, accessibility, and timeliness. The prop osed574

regulations would also include a provision stating that a description of the general approach that each covered unit is required to use for monitoring and reporting emissions (i.e., an approach using a continuous emissions monitoring system, an except ed monitoring system under appendices D and E to part 75, a low mass emissions excepted monitoring methodology under § 75.19, or an alternative monitoring system under subpart E of part 75) could be added to or changed in a Title V permit using minor permit modification procedures, provided that the requirements applicable to the monitoring and reporting addition or change were already incorporated elsewhere in the permit. As a result, minor permit modification procedures could be used to revise a unit’s Ti tle V permit to be consistent with any changes in the monitoring and reporting approach allowed for the unit by EPA through the monitoring system certification or petition process in the proposed trading program regulations. However, if the permit did not already incorporate the monitoring and reporting requirements applicable to the change, the permit would also have to be revised to incorporate these requirements, and this change would not qualify as a minor permit modification pursuant to 40 CFR 70.7(e)( 2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B).575 As new applicable requirements under Title V, the requirements for covered units under the final FIPs would be incorporated into covered sources’ existing Title V permits either pursuant to the provisions for reopeni ng for cause (40 CFR 70.7(f) and 40 CFR 71.7(f)) or the permit renewal provisions (40 CFR 70.7(c) and 71.7(c)) 104 . For sources newly subject to title V that would also be covered sources under the proposed FIPs, the initial Title V permit issued pursuant to 40 CFR 70.7(a) would include the final FIP requirements. In order to ensure that covered sources’ Title V permit provisions concerning the FIPs would reflect, properly and in a manner consistent from permit to permit, the trading program requirements and flexibilities, EPA intends to issue guidance, after promulgation of the final FIPs, to assist permitting authorities. This guidance would include information on permit issuance and permit modification requirements, as well as a permit content template th at would identify the applicable requirements under the trading program and thereby ensure

104 A p ermit is reopened for cause if any new applicable requirements (such as those under a FIP) become applicable to a covered source with a remaining permit term of 3 or more years. If the remaining permit term is less than 3 years, such new applicable requirements will be added to the permit during permit renewal. See 40 CFR 70.7(f)(1)(i) and 71.7(f)(1)(i).576

that they would be correctly and comprehensively reflected in each permit in a manner that would reduce the need for frequent permit revisions. Use of a permit cont ent template would also reduce the burden on sources in obtaining, on permitting authorities in issuing, and on EPA in reviewing, permits or permit revisions. IX. What benefits are projected for the proposed rule? In this section, we present the results of EPA’s analysis of the benefits of the emissions reductions in this proposal on PM2.5 and ozone air quality, public health , welfare , and the environment . These improvements were determined based upon air quality modeling of the 2014 base case and the “Sta te Budgets/Limited Trading” remedy proposed in this rule, as described in section V, above. I mplementation of this rule will very substantially lower the extent of nonattainment and maintenance problems for the annual and 24
- hour PM2.5 NAAQS and 8
- hour ozo ne NAAQS in the Eastern U.S. ( see section IX.A, below). The improvements in air quality will annually prevent thousands of premature deaths and other serious health effects ( see section IX.B, below) . We estimate the total monetized annual benefits to be approximately $ 120 billion to $ 290 billion or $ 110 billion to $ 270 billion in 2014 (at a 3 percent and a 7 percent discount rate, respectively) for577

the proposed “State Budgets/Limited Trading” remedy. There will be significant benefits that are not quanti fied. Notably, in 2012 the benefits are actually larger since greater emissions reductions are occurring from the baseline in that timeframe, as indicated in Table V.E
- 2, above. Because the magnitude of the PM2.5 co -benefits is largely driven by the conc entration
- response function for premature mortality, we examined alternate relationships between PM2.5 and premature mortality supplied by experts. Higher and lower co
-benefits estimates are plausible, but most of the expert
-based estimates fall between t hese two estimates above. 105 All monetized estimates are stated in 2006 dollars . Also note that the analytic baseline presents a unique situation. EPA has been directed to replace the CAIR; yet the CAIR remains in place and has led to significant emission s reductions in many states. A key step in the process of developing a 110(a)(2)(D)(i)(I) rule involves analyzing existing (base case) emissions to determine which states significantly contribute to downwind nonattainment and maintenance areas. EPA cann ot prejudge at this stage which states will be

105 Roman et al, 2008. Expert Judgment Assessment of the Mortality Impact of Changes in Ambient Fine Particulate Matter in the U.S. Environ. Sci. Technol., 42, 7, 2268

– 2274 .578

affected by the rule. For example, a state affected by CAIR may not be affected by the new rule and after the new rule goes into effect, the CAIR requirements will no longer apply. For a state covered by CAI R but not covered by the new rule, the CAIR requirements would not be replaced with new requirements, and therefore an increase in emissions relative to present levels could occur in that state. More fundamentally, the court has made clear that, due to le gal flaws, the CAIR rule cannot remain in place and must be replaced. If EPA’s base case analysis were to ignore this fact and assume that reductions from CAIR would continue indefinitely, areas that are in attainment solely due to controls required by CA IR would again face nonattainment problems because the existing protection from upwind pollution would not be replaced. For these reasons, EPA cannot assume in its base case analysis, that the reductions required by CAIR will continue to be achieved. Foll owing this logic, the 2012 base case shows emissions higher than current levels in some states. Because EPA has been directed to replace CAIR, EPA believes that for many states, the absence of the CAIR NO X program will lead to the status quo of the NO X Bu dget Program, which limits ozone
- season NO X emissions and ensures the operation of NOX controls in those states. Also , without the CAIR SO 2579

program, emission requirements in many areas would revert to the comparatively less stringent requirements of the T itle IV Acid Rain program. As a result, SO 2 emissions in many states would increase markedly in the 2012 base case relative to the present. Efforts to comply with ARP rules at the least
- cost would occur in many cases without the operation of existing scrubbers through use of readily available, inexpensive Title IV allowances. Notably, all known controls that are required under state laws, NSPS, consent decrees, and other enforceable binding commitments through 2014 are accounted for in the base case. It is against this backdrop that the Transport Rule is analyzed and that significant contribution to nonattainment and interference with maintenance must be addressed. A. The Impacts on PM2.5 and Ozone of the Proposed SO 2 and NOX Strategy The air quality modeling platform described in section IV.C. was used by EPA to model the impacts of the proposed SO 2 and NOx emissions reductions on annual average PM2.5 , 24
- hour PM2.5 , and 8
- hour ozone concentrations . In brief, we ran the CAMx model for the meteorological conditions in the580

year of 2005 for the Eastern U.S. modeling domain 106
. Modeling was performed for the 2014 base case and the 2014 “State Budgets/Limited Trading” scenario to assess the expected effects of the proposed regional strategy on projected PM2.5 and ozone design value concentrations and nonattainment and maintenance . The procedures used to project future design values and nonattainment and maintenance are described in section IV.C. The aggregate emissions in 2012 and 2014 for SO 2 and NOX are provided in Table V.E
- 2 in section V.E . The emissions by s tate are provided in Tables V.E
- 5 through V.E
- 7 in section V.E, and also in the Air Quality Modeling TSD. The projected 2014 concentrations of annual PM2.5 , daily PM2.5 , and ozone at each monitoring site in the East for which projections were made are provide d in the AQMTSD. The number of nonattainment and/or maintenance sites in the East for the 2012 base case , 2014 base case , and 2014 remedy for annual PM2.5 , daily PM2.5 , and ozone are provide d in Table IX - 1 107 . The average and peak reductions in annual

106 As described in the AQMTSD, the Eastern U.S. was modeled at a horizontal resolution of 12 x 12 km. The remainde r of the U.S. was modeled at a resolution of 36 x 36 km. 107 To provide a point of reference, Table IX
- 1 also includes the number of nonattainment and/maintenance sites based on ambient design values for the period 2003 through 2007.581

PM2.5 , daily PM2.5 , and ozone predicted at 2012 nonattainment and/or maintenance sites due the emissions reductions between 2012 and the 2014 remedy are provided in Table IX
2. TABLE IX- 1. PROJECTED REDUCTION IN NONATTAINMENT AND/OR MAINTENANCE PROBLEMS FOR PM2.5 AND OZONE IN THE EASTERN U.S.

Ambient (2003
- 2007) 2012

Base Case 2014

Base Case 2014 Proposed Remedy Percent

Reduction : 2012 Base Case vs. 2014 Remedy Percent

Reduction : 2014 Base Case vs. 20 14 Remedy Annual PM2.5 Nonattainment Sites 108 102 32 15 1 97% 93%
Annual PM2.5 Maintenance
Only Sites 21 16 7 1 94% 86%
Daily PM2.5 Nonattainment Sites 151 92 54 17 82% 69% Daily PM2.5 Maintenance
Only Sites 48 38 28 11 71% 61%

Ozone Nonattainment Sites 103 11 7 7 36% 0%
Ozone Maintenance
Only Sites 67 16 6 5 69% 17%

TABLE IX- 2. AVERAGE AND PEAK REDUCTION IN ANNUAL PM2.5 , DAILY PM2.5 , AND OZONE FOR SITES THAT ARE PROJECTED TO HAVE NONATTAINMENT AND/OR MAINTENANCE PROBLEMS IN THE 2012 BASE CASE
108 “Nonattainment” is use d to denote sites that are projected to have both nonattainment and maintenance problems.582 Average Reduction: 2012 Base Case to 2014 Remedy Peak

Reduction: 2012 Base case to 2014 Remedy Annual PM2.5 Nonattainment Sites 2.8 μg/m3 3.9 μg/m3 Annual PM2.5 Maintenance
- Only Sites 2.6 μg/m3 4.2 μg/m3 Daily PM2.5 Non attainment Sites 5.8 μg/m3 15.3 μg/m3 Daily PM2.5 Maintenance
- Only Sites 5.1 μg/m3 13.5 μg/m3 Ozone Nonattainment Sites 1.9 ppb 3.9 ppb Ozone Maintenance
- Only Sites 2.3 ppb 4.2 ppb

The information in Table IX
- 1 shows that there will be signifi cant reductions in the extent of nonattainment and maintenance problems for annual PM2.5 , daily PM2.5 , and ozone between 2012 and 2014 as a result of the emissions budgets in this proposal coupled with emissions reductions during this time period from othe r existing control programs. Specifically, t he results of the air quality modeling indicate that all but 1 site is projected to be in attainment and only 1 site is projected to have a maintenance problem for annual PM2.5 in 2014 with the emissions reducti ons expected from today’s proposal . As583

indicated in Table IX
- 2, the average reduction in annual PM2.5 across the 32 2012 nonattainment sites is 1.9 μ g/m3 and the peak reduction at an individual nonattainment site is 3.2 μ g/m3 . Comparable reductions are pro jected at annual PM2.5 maintenance
- only sites. For 24
- hour PM2.5 , we project that the number of nonattainment sites will be reduced by 82 percent and the number maintenance
- only sites by 71 percent in 2014 compared to the 2012 base case. The average redu ction in 24
- hour PM2.5 across the 92 2012 nonattainment sites is 5.8 μ g/m3 and the peak reduction at an individual nonattainment site is 15.3 μ g/m3 . Comparable reductions are projected at 24
- hour PM2.5 maintenance
- only sites. The emissions reductions in today’s proposal will result in considerable progress toward attainment and maintenance at the 28 sites that remain as nonattainment and/or maintenance for the 24
- hour the PM2.5 standard . On average for these 28 sites, the predicted amount of PM2.5 reduct ion in 2014 is more than half of what is needed for these sites to attain and/or maintain the 24

- hour standard. Thus, the SO 2 and NOX emissions reductions which will result from today’s proposal will greatly reduce the extent of PM2.5 nonattainment and mai ntenance problems by 2014 and beyond. As described above, these emissions reductions are584

expected to substantially reduce the number of PM2.5 nonattainment and/or maintenance sites in the East and make attainment easier for those counties that remain nonat tainment by substantially lowering PM2.5 concentrations . in residual nonattainment sites . The emissions reductions will also help those locations that may have maintenance problems. Based on the 201 2 base air quality modeling for ozone, 27 sites in the Ea st are projected to be nonattainment or have problems maintaining the 1997 ozone standard . The initial phase of summer NOX reductions in today’s proposal are projected to lower 8
- hour ozone concentration by 2.8 ppb, on average by 2014, at monitoring sites projected to be nonattainment and/or have maintenance problems in the 201 2 base case. We expect that the number of nonattainment sites will be reduced by 36 percent and the number maintenance
- only sites by 69 percent in 2014 compared to the 2012 base case . For the 1 2 sites expected to have residual nonattainment/maintenance problems in 2014 , the predicted ozone reductions provide nearly 10 percent of the amount needed for these sites to attain and/or maintain the ozone standard . Thus, our modeling indica tes that by 2014 the initial phase of summer NOX emissions reductions in this proposal will lower ozone concentrations in the East and585

help bring areas closer to attainment for the 8
- hour ozone NAAQS. B . Human Health Benefit Analysis To estimate the human health benefits of the proposed Transport Rule, we used the BenMAP model to quantify the changes in PM2.5 and ozone
- related health impacts and monetized benefits based on changes in air quality. We provide such estimates for the proposed remedy option. Notably, EPA expects that in 2014 the other two alternatives that the Agency considered have the same general level of benefits that will result from their implementation . The results of the analysis for the alternate SO 2 reduction scenarios are found in t he RIA. For context, it is important to note that the magnitude of the PM2.5 benefits is largely driven by the concentration response function for premature mortality. Experts have advised EPA to consider a variety of assumptions, including estimates bas ed both on empirical (epidemiological) studies and judgments elicited from scientific experts, to characterize the uncertainty in the relationship between PM2.5 concentrations and premature mortality. For this proposed rule we cite two key empirical studi es, one based5 86

on the American Cancer Society cohort study 109 and the other based on the extended Six Cities cohort study. 110 Table IX

– 3 presents the primary estimates of reduced incidence of PM2.5 and ozone
- related health effects in 2014 for the proposed and alternative remedies. In 2014, we estimate that PM
- related annual benefits of the proposed remedy include approximately 14,000 to 36,000 fewer premature mortalities, 9,200 fewer cases of chronic bronchitis, 22,000 fewer non
- fatal heart attacks, 11,00 0 fewer hospitalizations (for respiratory and cardiovascular disease combined), 10 million fewer days of restricted activity due to respiratory illness and approximately 1.8 million fewer work
- loss days. We also estimate substantial health improvements for children from fewer cases of upper and lower respiratory illness, acute bronchitis, and asthma attacks. As mentioned earlier, the reduced incidences of various effects would be greater in 2012 due to the larger emissions reductions that occur from the baseline. The lower reductions in emissions in 2014 result from further

109 Pope et al, 2002. “Lung Cancer, Cardiopulmonary Mortality, and Long
- term Exposure to Fine Particulate Air Pollution.” Journal of the American Medical Association 287:1132
- 1141. 110 Laden et al, 2006. “Reduction in Fine Particulate Air Pollution and Mortality.” American Journal of Respiratory and Critical Care Medicine . 173: 667
- 672.587

SO 2 controls in the proposed remedy because the baseline has much greater controls resulting from State actions and consent decrees. Ozone health
- related benefits are expected to occur during the summer ozone season (usually ranging from May to September in the Eastern U.S.). Based upon modeling for 2014, annual ozone related health benefits are expected to include between 50 and 230 fewer premature mortalities, 690 fewer hospital admissions for respiratory illnesses, 230 fewer emergency room admissions for asthma, 300,000 fewer days with restricted activity levels, and 110,000 fewer days where children are absent from school due to illnesses. When adding the PM and ozone
- related mortalities together, we find that the proposed Transport Rule will yield between 14,000 and 36,000 fewer premature mortalities. The following references are used in providing our estimates of ozone health
- related benefits: Bell, M.L., et al. 2004. Ozone and short
- term mortality in 95 US urban communities, 1987
- 2000. Journal of the American Medical Association. 292(19): p. 2372
- 8. Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine 173:667
- 672. Estimating the Public Health Benefits of Proposed Air Pollution Regulations. Washington, DC: The National Academies Press. Levy JI, Baxter LK, Schwartz J. 2009. Uncertainty and va riability in health
- related damages from coal
- fired588

power plants in the United States. Risk Anal. doi: 10.1111/j.1539

- 6924.2009.01227.x [Online 9 Apr 2009] Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002 . Lung Cancer, Cardiopulmonary Mortality, and Long
- term Exposure to Fine Particulate Air Pollution. Journal of the American Medical Association 287:1132
- 1141. TABLE IX–3. —

ESTIMATED ANNUAL REDUCTIONS IN INCIDENCE OF

HEALTH EFFECTSA Health Effect Proposed remedy PM-Related endpoints Premature Mortality Pope et al. (2002) (age >30) 14,000 (4,000

—25,000) Laden et al. (2006) (age >25) 36,000 (17,000

—56,000) Infant (< 1 year) 59 (
- 66

—180) Chronic Bronchitis 9,200 (320

—18,000) Non - fatal heart attack s (age > 18) 22,000 (5,800

—39,000) Hospital admissions

— respiratory (all ages) 3,500 (1,400

—5,500) Hospital admissions

— cardiovascular (age > 18) 7,500 (5,200

—8,900) Emergency room visits for asthma (age < 18) 14,000 (7,200

—21,000) Acute bronchitis (age 8
- 12) 21,000 (
- 4,800

—46,000) Lower respiratory symptoms (age 7
- 14) 250,000 (98,000

—400,000) Upper respiratory symptoms (asthmatics age 9
- 18) 190,000 (36,000

—350,000) Asthma exacerbation (asthmatics 6
- 18) 240,000 (8,300

—800,000) Lost work days (ages 18
- 65) 1,800,000 (1,500,000

— 2,000,000) Minor restricted
- activity days (ages 18
- 65) 10,000,000 (8,600,000

— 12,000,000)589

Ozone - related endpoints Premature mortality Bell et al. (2004) (all ages) 50 (17

—84) Levy et al. (2005) (all ages) 230 (160

—300) Hos pital admissions

— respiratory causes (ages > 65) 390 (
- 18

—740) Hospital admissions

— respiratory causes (ages <2) 300 (130

—460) Emergency room visits for asthma (all ages) 230 (
- 30

—730) Minor restricted
- activity days (ages 18
- 65) 300,000 (130,000

—480,000) School absence days 110,000 (38,000

—160,000) A Values rounded to two significant figures. Benefits from reducing other criteria pollutants and hazardous air pollutants and ecosystem effects are not included here.
C . Quantified and Monetized Visibility Benefits Only a subset of the expected visibility benefits

— those for Class I areas

—are included in the monetary benefits estimates we project for this rule. We anticipate improvement in visibility in residential areas where people live, work and recreate within the Transport Rule region for which we are currently unable to monetize benefits. For the Class I areas we estimate annual benefits of $ 3.4 billion beginning in 2014 for visibility improvements. Methodological limitations prevented us from quantifyi ng the visibility benefits of the alternate remedies. The590

value of visibility benefits in areas where we were unable to monetize benefits could also be substantial. D . Benefits of Reducing GHG Emissions When fully implemented in 2014, the proposed Transp ort Ru le would reduce emissions of CO 2 from electrical generating units by about 15 million metric tons annually. Using a "social cost of carbon" (SCC) estimate that accounts for the marginal dollar value (i.e., cost) of climate
- re lated damages resulting f rom CO 2 emissions, previous analyses including the RIA for the Final Rulemaking to Establish Light
- Duty Vehicle Greenhouse Gas Emissions Standards and Corporate Average Fuel Efficiency Standards have found the total benefit of CO 2 reductions is substantial . The monetary value of these avoided damages also grows over time. Readers interested in learning more about the calculation of the SCC metric should refer to the SCC TSD, Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 [ Docket No. EPA- HQ OAR- 2009
- 0472 ] . E . Total Monetized Benefits Table IX

– 4 presents the estimated monetary value of reductions in the incidence of health and welfare effects. These estimates account for increases in the value of risk591

reduction over time . As the table indicates, total benefits are driven primarily by the reduction in premature fatalities each year, which account for over 90 percent of total benefits. Table IX

– 5 presents the total monetized net benefits for 2014. A listing of the benefit ca tegories that could not be quantified or monetized in our benefit estimates are provided in Table IX

– 6 . TABLE IX– 4. —

ESTIMATED ANNUAL MONETARY VALUE OF REDUCTIONS IN INCIDENCE OF HEALTH AND WELFARE EFFECTS (billions of 2006$) A Health Effect Pollutant Prop osed remedy Premature mortality (Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates) 3% discount rate PM2.5 & O 3 $110 ($8.8

—$340) 7% discount rate PM2.5 & O 3 $100 ($7.9

—$300) Premature mortality (Laden et al. 2006 PM mortal ity and Levy et al. 2005 ozone mortality estimates)

3% discount rate PM2.5 & O 3 $280 ($25

—$820) 7% discount rate PM2.5 & O 3 $260 ($22

—$310) Chronic Bronchitis PM2.5 $4.3 ($0.2

—$20) Non - fatal heart attacks 3% discount rate PM2.5 $2.5 ($0.4

—$6) 7% discount rate PM2.5 $2.4 ($0.4

—$5.9) Hospital admissions

— respiratory PM2.5 & O 3 $0.06 ($0.03

—$0.1) Hospital admissions

— cardiovascular PM2.5 $0.2 ($0.1

—$0.3)592

Emergency room visits for asthma PM2.5 & O 3 $0.005 ($0.002

—$0.008) Acute bronchitis PM2.5 $0.009 (
- $0.0004

—$0.03) Lower respiratory symptoms PM2.5 $0.005 ($0.002

—$0.009) Upper respiratory symptoms PM2.5 $0.006 ($0.001

—$0.014) Asthma exacerbation PM2.5 $0.012 ($0.001
-- $0.046) Lost work days PM2.5 $0.2 ($0.19

—$0.24) School loss days $0.01 ($0.004

—$0.013) Minor restricted
- activity days PM2.5 & O 3 $0.64 ($0.34

—$0.97) Recreational visibility, Class I areas PM2.5 $3.6 Total benefits based on Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates 3% discount rate PM2.5 & O 3 $120 ($10—$360) 7% discount rate PM2.5 & O 3 $110 ($9—$330) Total benefits based on Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates 3% discount rate PM2.5 & O 3 $290 ($26—$840) 7% discount rate PM2.5 & O 3 $270 ($24—$760) A Estimates rounded to two significant figures

E. How do the b enefits c ompare to the c osts of this p roposed rule? The estimated annual private costs to implement the emission reduction requirements of the proposed rule for593

the T ransport Rule region are $3 . 7 billion in 2012 and $2.8 billion in 2014 (2006$) for the proposed remedy option, $4 . 2 billion in 2012 and $2.7 billion in 2014 for the State Budgets/Intrastate Trading remedy option, and $4.3 billion in 2012 and $3.4 billion i n 2014 for the direct control remedy option. These costs are the annual incremental electric generation production costs that are expected to occur with the Transport Rule. The EPA uses these costs as compliance cost estimates in developing cost
- effectiveness estimates. In estimating the net benefits of regulation, the appropriate cost measure is ‘‘social costs.’’ Social costs represent the welfare costs of the rule to society. These costs do not consider transfer payments (such as taxes) that are simply redistributions of wealth. The social costs of this rule (thus reflecting the proposed remedy option) are estimated to be approximately $ 2.0 billion in 2014 assuming a 3 percent discount rate. These costs become $ 2.2 billion in 2014, if one assumes a 7 p ercent discount rate. Thus, the net benefit (social benefits minus s ocial costs) as will be shown in Table IX
- 5 for the proposed remedy option is approximately $120 to 292 billion or $109 to 264 billion (3 percen t and 7 percent discount rates) in 2014. I mplementation of the rule is expected to provide594

society with a substantial net gain in social welfare based on economic efficiency criteria. The annu alized regional cost of the proposed rule , as quantified here, is EPA’s best assessment of t he cost of imp lementing the proposed option. These costs are generated from rigorous economic modeling of changes in the power sector expected from the proposed rule . This type of analysis using IPM has undergone peer review and been upheld in f ederal courts. The dir ect cost includes, but is not limited to, capital investments in pollution controls, operating expenses of the pollution controls, investments in new generating sources, and additional fuel expenditures. The EPA believes that these costs reflect, as close ly as possible, t he additional costs of the proposed option to industry. The relatively small cost associated with monitoring emissions, reporting, and recordkeeping for affected sources is not included in these annualized cost estimates, but EPA has done a separate analysis and estimated the cost to less than $ 28 million (see section X II .B., Paperwork Reduction Act). However, there may exist certain costs that EPA has not quantified in these estimates. These costs may include co sts of transitioning to t his rule , such as the costs associated with the retirement of smaller or less efficient EGUs,595

employment shifts as workers are retrained at the same company or re - employed elsewhere in the economy, and certain relatively small pe rmitting costs associated w ith T itle V that new program entrants face. An optimization model was employed that assumes cost minimization . Costs may be understated if the regulated community chooses not to minimize its compliance costs in the same manner to comply with the rules. Although EPA has not quantified these costs, the Agency believes that they are small compared to the quantified costs of the program on the power sector. However, EPA’s experience and results of independent evaluation suggests that costs are likely to be l ower by some degree (see RIA for details). The annualized cost estimates presented are the best and most accurate based upon available information. In a separate analysis, EPA estimates the indirect costs and impacts of higher electricity prices on the e ntire economy. These impacts are summarized in section X of this preamble and in the RIA for this proposed rule.
TABLE IX–5. —SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET

BENEFITS OF THE TRANSPORT RULE IN 2014 [Billions of 2006 dollars] Description Propose d remedy Social costs 3 percent discount rate $2.0 7 percent discount rate 2.2596

Social benefits 3 percent discount rate $122 to 294 + B 7 percent discount rate 111 to 266 + B Health
- related benefits 3 percent discount rate $118 to 290 7 percent discount rate 107 to 262 Visibility benefits 3 percent discount rate $3.6 7 percent discount rate $3.6 Annual net benefits (benefits
- costs) 3 percent discount rate $120 to 292 7 percent discount rate $109 to 264

a All estimates are rounded to th ree significant digits and represent annualized benefits and costs anticipated for 2014. Estimates relate to the complete Transport Rule program. b Note that costs are the annual total costs of reducing pollutants including NO X and SO 2 in the Transport Rul e region. c As this table indicates, total benefits are driven primarily by PM2.5 - related health benefits. The reduction in premature fatalities each year accounts for over 90 percent of total monetized benefits 2014. Benefits in this table are nationwide (with the exception of visibility) and are associated with NO X and SO 2 reductions for the EGU source category. Ozone benefits represent benefits in the eastern United States. Visibility benefits represent benefits in Class I areas in the southeastern Un ited States. d Not all possible benefits or disbenefits are quantified and monetized in this analysis. Potential benefit categories that have not been quantified and monetized are listed in Table I X

– 6 . We represent the value of unquantified benefits and disbenefits with a “B.” e Valuation assumes discount ing over the SAB
- recommended 20 year segmented lag structure described in chapter 4 of the Regulatory Impact Analysis for the Clean Air Interstate Rule (March 2005). Results reflect 3 percent and 7 percen t discount rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000 and OMB, 2003).174 f Net benefits are rounded to the nearest $1 billion . Columnar totals may not sum due to rounding. Every benefit
- cost analysis examining the potential effects of a change in environmental protection requirements is limited to some extent by data gaps, limitations in model capabilities (such as geographic597

coverage), and uncertainties in the underlying scientific and economic studies us ed to configure the benefit and cost models. Gaps in the scientific literature often result in the inability to estimate quantitative changes in health and environmental effects. Gaps in the economics literature often result in the inability to assign ec onomic values even to those health and environmental outcomes that can be quantified. While uncertainties in the underlying scientific and economics literatures (that may result in overestimation or underestimation of benefits) are discussed in detail in t he economic analyses and its supporting documents and references, the key uncertainties which have a bearing on the results of the benefit
- cost analysis of this rule include the following:

• EPA’s inability to quantify potentially significant benefit categories; • Uncertainties in population growth and baseline incidence rates; • Uncertainties in projection of emissions inventories and air quality into the future; • Uncertainty in the estimated relationships of health and welfare effects to changes in pollu tant concentrations including the shape of the C

– R function, the size of the effect estimates, and the598 relative toxicity of the many components of the PM mixture; • Uncertainties in exposure estimation; and • Uncertainties associated with the effect of pot ential future actions to limit emissions. Despite these uncertainties, we believe the benefit
cost analysis provides a reasonable indication of the expected economic benefits of the rulemaking in future years under a set of reasonable assumptions. This app roach calculates a mean value across VSL estimates derived from 26 labor market and contingent valuation studies published between 1974 and 1991. The mean VSL across these studies is $6.3 million (2000$). 111 The benefits estimates generated for this rule a re subject to a number of assumptions and uncertainties, which are discussed throughout the RIA document. As Table IX

– 4 indicates, total benefits are driven primarily by the reduction in premature mortalities each year. Some key assumptions underlying the primary estimate for the premature mortality category include the following:

111 In this analysis, we adjust the VSL to account for a different currency year (2 006$) and to account for income growth to 2014. After applying these adjustments to the $6.3 million value, the VSL is $8.5 million.599 (1) EPA assumes inhalation of fine particles is causally associated with premature death at concentrations near those experienced by most Americans on a daily basis. Plausible biological mechanisms for this effect have been hypothesized for the endpoints included in the primary analysis and the weight of the available epidemiological evidence supports an assumption of causality. (2) EPA assumes all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality. This is an important assumption, because the proportion of certain components in the PM mixture produced via precursors emitted from EGUs may differ significantly from direct PM released from automotive engines and other industrial sources, but no clear scientific grounds exist for supporting differential effects estimates by particle type. (3) We assume that the health impact function for fine particles is linear down to the l owest air quality levels modeled in this analysis. Thus, the estimates include health benefits from reducing fine particles in areas with varied concentrations of PM2.5 , including both regions that are in attainment with fine particle600 standard and those t hat do not meet the standard down to the lowest modeled concentrations. The EPA recognizes the difficulties, assumptions, and inherent uncertainties in the overall enterprise. The analyses upon which the Transport Rule is based were selected from the pee r - reviewed scientific literature. We used up
- to - date assessment tools, and we believe the results are highly useful in assessing this rule. There are a number of health and environmental effects that we were unable to quantify or monetize. A complete be n efit
- cost analysis of the Transport Rule requires consideration of all benefits and costs expected to result from the rule, not just those benefits and costs which could be expressed here in dollar terms. A listing of the benefit categories that were not quantified or monetized in our estimate are provided in Table IX - 6 . F . What a re the unquantified and unmonetized b enefits of the Transport Rule emissions r eductions? Important benefits beyond the human health and welfare benefits resulting from reductions in ambient levels of PM2.5 and ozone in the Eastern United States are expected to occur from this rule. These other benefits occur both directly from NO X and SO 2 emissions reduction s . These benefits are listed in Table IX

– 6 . Some of the more601

important e xamples include: Reductions in NO X and SO 2 emissions required by the Transport Rule will reduce acidification and, in the case of NO X , eutrophication of water bodies. Reduced nitrate contamination of drinking water is another possible benefit of the rule. This proposed rule will also reduce acid and particulate deposition that causes damages to cultural monuments, as well as, soiling and other materials damage. To illustrate the important nature of benefit categories we are currently unable to monetize, we discuss four categories of public welfare and environmental impacts related to reductions i n emissions required by the Transport Rule : Reduced acid deposition, reduced eutrophication of estuaries, and reduced vegetation impairment from ozone. 1 . What a re the b enefits of r educed deposition of s ulfur and n itrogen to a quatic, f orest, and c oastal e cosystems? Atmospheric deposition of sulfur and nitrogen, often referred to as acid rain, occurs when emissions of SO 2 and NOX react in the atmosphere (with water, oxygen, and oxidants) to form various acidic compounds. These acidic compounds fall to earth in either a wet form (rain, snow, and fog) or a dry form (gases and particles). Prevailing winds can transport acidic compounds hundreds of miles, across State b orders. Together these emissions are602

deposited onto terrestrial and aquatic ecosystems across the U.S., contributing to the problems of acidification, nutrient enrichment, and methylmercury production. In addition, NO x is a precursor to ozone, which can impair vegetation.
a . Acid Deposition and Acidification of Lakes and Streams The extent of adverse effects of acid deposition on freshwater and forest ecosystems depends largely upon the ecosystem’s ability to neutralize the acid. The neutralizing abili ty [key indicator is termed Acid Neutralizing Capacity (ANC)] depends largely on the watershed’s physical characteristics, such as geology, soils, and size. Acidic conditions occur more frequently during rainfall and snowmelt that cause high flows of wate r and less commonly during low
- flow conditions, except where chronic acidity conditions are severe. Biological effects are primarily attributable to a combination of low pH and high inorganic aluminum concentrations. Biological effects of episodes include reduced fish condition factor, changes in species composition and declines in aquatic species richness across multiple taxa, ecosystems and regions, as well as fish mortality. Waters that are sensitive to acidification tend to be located in small waters heds that have few alkaline minerals and shallow soils. Conversely,603

watersheds that contain alkaline minerals, such as limestone, tend to have waters with a high ANC. Areas especially sensitive to acidification include portions of the Northeast (particula rly, the Adirondack and Catskill Mountains, portions of New England, and streams in the mid
Appalachian highlands) and southeastern streams . This regulatory action will decrease acid deposition in the transport region and is likely to have positive effect s on the health and productivity of aquatic ecosystems in the region. b . Acid Deposition and Forest Ecosystem Impacts Acidifying deposition has altered major biogeochemical processes in the U.S. by increasing the nitrogen and sulfur content of soils, accel erating nitrate and sulfate leaching from soil to drainage waters, depleting base cations (especially calcium and magnesium) from soils, and increasing the mobility of aluminum. Inorganic aluminum is toxic to some tree roots. Plants affected by high leve ls of aluminum from the soil often have reduced root growth, which restricts the ability of the plant to take up water and nutrients, especially calcium (U. S. EPA, 2008f). These direct effects can, in turn, influence the response of these plants to clima tic stresses such as droughts and cold temperatures. They can also influence the sensitivity604

of plants to other stresses, including insect pests and disease (Joslin et al., 1992) leading to increased mortality of canopy trees. Both coniferous and decidu ous forests throughout the eastern U.S. are experiencing gradual losses of base cation nutrients from the soil due to accelerated leaching for acidifying deposition. This change in nutrient availability may reduce the quality of forest nutrition over the long term. Evidence suggests that red spruce and sugar maple in some areas in the eastern U.S. have experienced declining health because of this deposition. For red spruce, ( Picea rubens ) dieback or decline has been observed across high elevation landscapes of the northeastern U.S., and to a lesser extent, the southeastern U.S., and acidifying deposition has been implicated as a causal factor (DeHayes et al., 1999). This regulatory action will decrease acid deposition in the transport region and is likely to have positive effects on the health and productivity of forest systems in the region.
c . Coastal Ecosystems Since 1990, a large amount of research has been conducted on the impact of nitrogen deposition to coastal waters. Nitrogen is often the limitin g nutrient in coastal605

ecosystems. Increasing the levels of nitrogen in coastal waters can cause significant changes to those ecosystems. In recent decades, human activities have accelerated nitrogen nutrient inputs, causing excessive growth of algae and leading to degraded water quality and associated impairments of estuarine and coastal resources. Atmospheric deposition of nitrogen is a significant source of nitrogen to many estuaries. The amount of nitrogen entering estuaries due to atmospheric deposit ion varies widely, depending on the size and location of the estuarine watershed and other sources of nitrogen in the watershed. A recent assessment of 141 estuaries nationwide by the National Oceanic and Atmospheric Administration (NOAA) concluded that 1 9 estuaries (13 percent ) suffered from moderately high or high levels of eutrophication due to excessive inputs of both N and phosphorus, and a majority of these estuaries are located in the coastal area from North Carolina to Massachusetts (NOAA, 2007 ). For estuaries in the Mid
-Atlantic region, the contribution of atmospheric distribution to total N loads is estimated to range between 10 percent and 58 percent (Valigura et al., 2001 ). Eutrophication in estuari es is associated with a range of adverse ecological effects. The conceptual framework606

developed by NOAA emphasizes four main types of eutrophication effects

—low dissolved oxygen (DO), harmful algal blooms (HABs), loss of submerged aquatic vegetation (SAV) , and low water clarity. Low DO disrupts aquatic habitats, causing stress to fish and shellfish, which, in the short
- term, can lead to episodic fish kills and, in the long
- term, can damage overall growth in fish and shellfish populations. Low DO also deg rades the aesthetic qualities of surface water. In addition to often being toxic to fish and shellfish, and leading to fish kills and aesthetic impairments of estuaries, HABs can, in some instances, also be harmful to human health. SAV provides critical habitat for many aquatic species in estuaries and, in some instances, can also protect shorelines by reducing wave strength; therefore, declines in SAV due to nutrient enrichment are an important source of concern. Low water clarity is the result of accumulations of both algae and sediments in estuarine waters. In addition to contributing to declines in SAV, high levels of turbidity also degrade the aesthetic qualities of the estuarine environment. Estuaries in the eastern United States are an important source of food production, in particular fish and shellfish production. The estuaries are capable of supporting large stocks of resident commercial species, and607

they serve as the breeding grounds and interim habitat for several migratory species. This rul e is anticipated to reduce nitrogen deposition in the Transport Rule region. Thus, reductions in the levels of nitrogen deposition will have a positive impact upon current eutrophic conditions in estuaries and coastal areas in the region. d . Mercury Methy lation and Deposition Mercury is a highly neurotoxic contaminant that enters the food web as a methylated compound, methylmercury (U.S. EPA, 2008d). The contaminant is concentrated in higher trophic levels, including fish eaten by humans. Experimental ev idence has established that only inconsequential amounts of methylmercury can be produced in the absence of sulfate. Current evidence indicates that in watersheds where mercury is present, increased SO X deposition very likely results in methylmercury
accumulation in fish (Drevnick et al., 2007; Munthe et al, 2007). The SO 2 ISA (U.S. EPA, 2008) concluded that evidence is sufficient to infer a casual relationship between sulfur deposition and increased mercury methylation in wetlands and aquatic environment s. 2 . Ozone Vegetation E ffects608 Ozone causes discernible injury to a wide array of vegetation (U.S. EPA, 2006; Fox and Mickler, 1996). In terms of forest productivity and ecosystem diversity, ozone may be the pollutant with the greatest potential for regi onal
- scale forest impacts (U.S. EPA, 2006). Studies have demonstrated repeatedly that ozone concentrations commonly observed in polluted areas can have substantial impacts on plant function (De Steiguer et al., 1990; Pye, 1988). Assessing the impact of gr ound
- level ozone on forests in the eastern United States involves understanding the risks to sensitive tree species from ambient ozone concentrations and accounting for the prevalence of those species within the forest. As a way to quantify the risks to p articular plants from ground
- level ozone, scientists have developed ozone
- exposure/tree

- response functions by exposing tree seedlings to different ozone levels and measuring reductions in growth as “biomass loss.” Typically, seedlings are used because the y are easy to manipulate and measure their growth loss from ozone pollution. The mechanisms of susceptibility to ozone within the leaves of seedlings and mature trees are identical, and the decreases predicted using the seedlings should be related to the decrease in overall plant fitness609

for mature trees, but the magnitude of the effect may be higher or lower depending on the tree species (Chappelka and Samuelson, 1998). In areas where certain ozone
sensitive species dominate the forest community, the biomass loss from ozone can be significant. Significant biomass loss can be defined as a more than 2 percent annual biomass loss, which would cause long term ecological harm as the short
- term negative effects on seedlings compound to affect long
- term forest health (Heck, 1997). Urban ornamentals are an additional vegetation category likely to experience some degree of negative effects associated with exposure to ambient ozone levels. Because ozone causes visible foliar injury, the aesthetic value of ornamen tals (such as petunia, geranium, and poinsettia) in urban landscapes would be reduced (U.S. EPA, 2007). Sensitive ornamental species would require more frequent replacement and/or increased maintenance (fertilizer or pesticide application) to maintain the desired appearance because of exposure to ambient ozone (U.S. EPA, 2007). In addition, many businesses rely on healthy
- looking vegetation for their livelihoods (e.g., horticulturalists, landscapers, Christmas tree growers, farmers of leafy crops, etc.) a nd a variety of ornamental610

species have been listed as sensitive to ozone (Abt Associates, 1995). 3 . Other Health or Welfare Disbenefits of the Transport Rule That Have Not Been Quantified In contrast to the additional benefits of the proposed rule discu ssed above, it is also possible that this rule will result in disbenefits in some areas of the region. Current levels of nitrogen deposition in these areas may provide passive fertilization for forest and terrestrial ecosystems where nutrients are a limiti ng factor and for some croplands. The effects of ozone and PM on radiative transfer in the atmosphere can also lead to effects of uncertain magnitude and direction on the penetration of ultraviolet light and climate. Ground level ozone makes up a small p ercentage of total atmospheric ozone (including the stratospheric layer) that attenuates penetration of ultraviolet

—b (UVb) radiation to the ground. The EPA’s past evaluation of the information indicates that potential disbenefits would be small, variable , and with too many uncertainties to attempt quantification of relatively small changes in average ozone levels over the course of a year (EPA, 2005a). The EPA’s most recent provisional assessment of the currently available information indicates that poten tial but unquantifiable benefits may also arise from611

ozone - related attenuation of UVb radiation (EPA, 2005b). Sulfate and nitrate particles also scatter UVb, which can decrease exposure of horizontal surfaces to UVb, but increase exposure of vertical surf aces. In this case as well, both the magnitude and direction of the effect of reductions in sulfate and nitrate particles are too uncertain to quantify (EPA, 2004). Ozone is a greenhouse gas, and sulfates and nitrates can reduce the amount of solar radia tion reaching the earth, but EPA believes that we are unable to quantify any net climate
- related disbenefit or benefit associated with the combined ozone and PM reductions in this rule. Additionally, from analyses of the benefits of the Acid Rain Program, EPA has seen that substantial health and environmental benefits that are likely to occur for Canadians because 80 percent of the Canadian population lives within 40 miles of the US
- Canada border. TABLE IX– 6. —

UNQUANTIFIED AND NON-MONETIZED EFFECTS OF THE

TR ANSPORT RULE Pollutant/ Effect Endpoint

PM: health a Low birth weight

Pulmonary function Chronic respiratory diseases other than chronic bronchitis Non - asthma respiratory emergency room visits UVb exposure (+/

- ) c PM: welfare Household soiling612 Visibility in residential and non
- class I areas UVb exposure (+/

- ) c Global climate impacts c
Ozone: health Chronic respiratory damage

Premature aging of the lungs Non - asthma respiratory emergency room visits Increased exposure to UVb (+/

- ) c

Ozone: welfare Yields for:

-- Commercial forests

-- Fruits and vegetables, and

-- Other commercial and noncommercial crops Damage to urban ornamental plants Recreational demand from damaged forest aesthetics Ecosystem functions Increased exposure to UVb ( +/

- ) c

NO2 : health Respiratory hospital admissions

Respiratory emergency department visits Asthma exacerbation Acute respiratory symptoms Premature mortality Pulmonary function

NO2 : welfare Commercial fishing and forestry from acidic deposition Commercial fishing, agriculture and forestry from nutrient deposition Recreation in terrestrial and estuarine ecosystems from nutrient deposition Other ecosystem services and existence values for currently healthy ecosystems

SO2 : health Respiratory hospital admissions

Asthma emergency room visits Asthma exacerbation Acute respiratory symptoms Premature mortality Pulmonary function
SO2 : welfare Commercial fishing and forestry from acidic deposition Recreation in terrestrial and aquatic ec osystems from acid deposition Increased mercury methylation A In addition to primary economic endpoints, there are a number of biological responses that have been associated with PM health effects including morphological changes and altered host defense mechanisms. The public health613

impact of these biological responses may be partly represented by our quantified endpoints. B Cohort estimates are designed to examine the effects of long term exposures to ambient pollution, but relative risk estimates may also incorporate some effects due to shorter term exposures ( see Kunzli et al. (2001) for a discussion of this issue). While some of the effects of short term exposure are likely to be captured by the cohort estimates, there may be additional premature mortality from short term PM exposure not captured in the cohort estimates included in the primary analysis. C May result in benefits or disbenefits. X. Economic Impacts For the affected region, the projected annual private increment al costs of the proposed remedy option to the power industry are $3.7 billion in 2012 and $2.8 billion in 2014. For the State Budgets/Intrastate Trading remedy, projected annual private incremental costs are $4.2 billion in 2012 and $2.7 billion in 2014. Finally, for the direct control remedy, the projected annual private incremental costs are $4.3 billion in 2012 and $3.4 billion in 2014. These costs represent the private compliance cost to the electric generating industry of reducing NO X and SO 2 emissi ons to meet the requirements set forth in the rule. Estimates are in 2006 dollars. In estimating the net benefits of regulation, the appropriate cost measure is ‘‘social costs.’’ Social costs represent the welfare costs of the rule to society. These cost s do not consider transfer payments (such as taxes)614

that are simply redistributions of wealth. The social costs of this rule for the proposed remedy option are estimated to be approximately $2.0 billion in 2014 assuming a 3 percent discount rate. These c osts become $2.2 billion in 2014 assuming a 7 percent discount rate. For the State Budgets/Intrastate Trading remedy, social costs are estimated to be approximately $2.5 billion in 2014 assuming a 3 percent discount rate and $2.7 billion in 2014 assuming a 7 percent discount rate. Finally, for the direct control remedy, social costs are estimated to be approximately $2.7 billion in 2014 assuming a 3 percent discount rate and $2.9 billion in 2014 assuming a 7 percent discount rate. Overa ll, the economi c impacts of the Transport Rule proposal are modest in 2014 , particularly in light of the large benefits ($122 to $294 billion annually at a 3 percent discount rate and $111 to $266 billion annually at a 7 percent discount rate) we expect as shown earlier in this preamble ( see section IX for more details) . Ultimately, we believe the electric power industry will pass along most of the costs of the rule to consumers , so that the costs of the rule will largely fall upon the consumers of electricit y. For more information on electricity price changes that result from this proposal,615

please refer to s ection XII.H (Statement of Energy Effects) later in this preamble. Ve2M For this proposed rule, EPA analyzed the costs using the Integrated Planning Model (IPM). The IPM is a dynamic linear programming model that can be used to examine the economic impacts of air po llution control policies for SO 2 and NOX throughout the contiguous United States for the entire power system. Docume ntation for IPM can be found in the docket for this rulemaking or at http://www.epa.gov/airmarkets/progsregs/epa

- ipm/index.html . Analysis of impacts on affected industries outside of the electric power generating sector are estimated by the Economic Model for Policy Analysis (EMPAX), a dynamic model that can generate price and output changes for output affected by electricity price changes due to air pollution control policies and also estimates of social costs associated with such policies. Docume ntation for EMPAX can be found in the docket for this rulemaking or at http://www.epa.gov/ttn/ecas/EMPAX.htm . Also note that as explained in section IV.A.3, the baseline used in this analysis assumes no CAIR. If EPA’s base case analysis were to ass ume that reductions from CAIR would continue indefinitely, areas that are in attainment616

solely due to controls required by CAIR would again face nonattainment problems because the existing protection from upwind pollution would not be replaced. As explain ed in that section, EPA believes that this is the most appropriate baseline to use for purposes of determining whether an upwind state has an impact on a downwind monitoring site in violation of section 110(a)(2)(D). XI. Incorporating End-use Energy Efficiency into the Proposed Transport Rule A. Background EPA believes that achievement of energy efficiency improvements in homes, buildings, and industry is an important component of achieving emissions reductions from the power sector while minimizing associ ated compliance costs. By reducing electricity demand, energy efficiency avoids emissions of all pollutants associated with electricity generation, including emissions of NOX and SO 2 targeted by this rule. While all remedy options considered

-- including the proposed remedy (State Budgets/Limited Trading)
-- will lead to a modest increase in the relative cost - effectiveness of energy efficiency investments by internalizing environmental costs associated with these pollutants, EPA is interested in consideri ng additional means by which energy efficiency can be encouraged through617

this proposed rule. 1. What is end
- use energy efficiency? End
- use energy efficiency (hereafter, “energy efficiency”) in the context of this proposed rule refers to activities that re duce the demand for electricity from EGUs in affected states. Energy efficiency improvements are pursued through the efforts of state agencies, independent program administrators (e.g. Vermont Energy Investment Corporation), electric utilities, energy service companies, and other commercial entities. Examples of common energy efficiency projects include re
- commissioning of commercial buildings, rebates for energy efficient appliances, and home energy audits. 2. How does energy efficiency contribute to co st - effective reductions of air emissions from EGUs? EPA recognizes that significant opportunity remains for energy efficiency improvements in businesses, homes, and industry. However, there are several informational and market barriers that limit investme nt in cost
- effective energy efficient practices. Several federal programs authorized under the Act, including ENERGY STAR, are designed to address these barriers. By reducing the demand for electricity energy efficiency reduces the need for investments i n EGU618

emissions control technologies in order to meet the limits of an established state emissions budget and can often be implemented at a lower cost than traditional control technologies. Section III.E in this preamble further discusses the importance o f electricity demand reductions as a component of EPA’s broader air quality improvement strategy for the power sector. EPA is available to assist states in quantifying the reduction in compliance costs of air regulatory programs, including the proposed rul e, that can be realized through effective energy efficiency policies and programs. 3. How does the proposed rule support greater investment in energy efficiency? By requiring reductions in the emissions of NOX and SO 2 from power plants in affected states, a transport rule will lead to the internalization of costs associated with reducing the environmental effects of these pollutants. Since the economics of energy efficiency investments are directly related to power generation costs, this will improve the r elative cost
- effectiveness of these investments. Over time, this effect is expected to lead to increases in energy efficiency investments and associated benefits. 4. How have EPA and states previously integrated energy619

efficiency into air regulatory progr ams? Congress, EPA, and states have all recognized the value of incorporating energy efficiency into air regulatory programs. Several allowance
-based programs
-- including the Acid Rain Program, EPA’s NOX Budget Trading program, and the Regional Greenhous e Gas Initiative (an effort of 10 states from the Northeast and Mid
-Atlantic regions)

– have provided mechanisms for rewarding energy efficiency projects through either the award of emissions allowances, typically through the use of a fixed set
- aside pool, or the use of revenues obtained through the auction of emissions allowances. The emissions caps established by these programs are unaffected by this approach, however, compliance costs are reduced (to the extent electricity demand reductions are realized ) as are the emissions of
non - capped pollutants from affected EGUs. In addition to these allowance
-based programs, EPA has also established, through Guidance 112 , a means for recognizing the emissions benefits of energy efficiency in SIPs and has approved their use in individual state plans. B. Incorporating End
- us e Energy Efficiency into the
112 U.S. EPA. 2004. Guidance o n State Implementation Plan (SIP) Credits f or Emission Reductions From Electric
- Sector Energy Efficiency And Renewable Energy Measures

. August. http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf620

Transport Rule As discussed previously, EPA believes that increasing end
- use energy efficiency can be an effective approach for reducing compliance costs of the proposed rule, as well as for reducing EGU emissions that are not the target of this rule including mercury, other toxics, and carbon dioxide. While EPA believes the proposed rule will make energy efficiency investments more competitive, the Agency is seeking comments on additional ways in which this rule could further encourage these investments. 1. Options that C ould be U sed to I ncorporate E nergy E fficiency into Allowance B ased P rograms As discussed previously, allowance
-based programs (such as the proposed Stat e Budgets/Limited Trading remedy and the alternative State Budgets/Intrastate Trading remedy) of EPA and states have supported energy efficiency projects through the use of auction revenues or the award of allowances. EPA considered these options in devel oping this proposal but, for the reasons described later , decided not to include either option in this proposal. 2. Why did EPA not propose these options? The emission reductions requirements of the proposed rule are implemented through proposed FIPs. This means, among other things, that EPA allocates the emission621

allowances directly to individual sources. In contrast, when allowance based programs are implemented through SIPs, states may have significant flexibility to determine the methodology used to allocate or auction allowances in their budgets. Under the proposed FIPs, EPA would allocate allowances to sources in a manner consistent with the methodology used to determine each state’s budget. EPA believes this approach is appropriate because of the link between the allowance allocation methodology and the significant contribution determinations. EPA requests comment on whether EPA has authority to and whether it would be appropriate for EPA to consider energy efficiency considerations in develop ing the allowance allocation methodology. In addition, because the emission reduction requirements are implemented through FIPs, any auction of allowances would be conducted by EPA. As discussed previously in section V.D.5.b, pursuant to the Miscellaneous Receipts Act, any revenues from a federal auction of allowances must go to the U.S. Treasury. This precludes the use of proceeds from such an auction to reward energy efficiency projects. In addition, and as also discussed previously in sections III.A an d III.B.3, EPA anticipates further622

revisions to the PM2.5 and ozone NAAQS and intends to issue subsequent proposals to address the interstate transport requirements of section 110(a)(2)(D)(i)(I) with respect to those new NAAQS. The emissions reduction requirements identified in any such rules could be implemented through SIPs. The SIP process could give states significant flexibility in regards to allocation and auctioning of allowances. This flexibility could be used by states to support energy efficien cy projects through the use of auction revenues or the award of allowances. EPA is seeking comment on the discussion within this section and the use of these and other approaches for encouraging energy efficiency within the proposed rule. XII . Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities.623 Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866 and any changes made in response to OMB recommendations have been documented in the docket for this action. B. Paperwork Reduction Ac t The information collection requirements in the proposed rule have been submitted for approval to OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq . The information collection requirements are not enforceable until OMB approves them. The inf ormation collection activities in this proposed rule include monitoring and the maintenance of records. The information generated by these activities will be used by EPA to ensure that affected facilities comply with the emission limits and other requirements. Records and reports are necessary to enable EPA or States to identify affected facilities that may not be in compliance with the requirements. Based on reported information, EPA will decide which units and what records or processes should be inspec ted. The amendments do not require any notifications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance. These recordkeeping and reporting requi rements are specifically624

authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to EPA for which a claim of confidentiality is made will be safeguarded according to EPA policies in 40 CFR part 2, subpart B, Confidentiality of Business I nformation. The record
- keeping and reporting burden to sources resulting from states choosing to participate in a regional cap - and
- trade program is approximately $28 million annually. This estimate includes the annualized cost of installing and operating appropriate SO 2 and NO x emissions monitoring equipment to measure and report the total emissions of these pollutants from affected EGUs (serving generators greater than 25 megawatt electrical). The burden to state and local air agencies includes any
nece ssary SIP revisions, performance of monitoring certification, and fulfilling of audit responsibilities. More information on the ICR analysis is included in the proposed Transport Rule docket. Burden is defined at 5 CFR 1320.3(b). An Agency may not condu ct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB,625

the Agency will publish a technical amendment to 40 CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this final rule. C. Regulatory Flexibility Act The Regulat ory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies th at the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of ass essing the impacts of this proposed rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration’s (SBA) regulations at 13 CFR 121.201 . F or the electric power generation industry, the small business size standard is an ultimate par ent entity defined as having a total electric output of 4 million megawatt
- hours (MW
- hr ) or less in the previous fiscal year.626 (2) A small governmental jurisdiction that is a government of a city, county, town, school district or special district with a p opulation of less than 50,000; and (3) A small organization that is any not
- for
-profit enterprise which is independently owned and operated and is not dominant in its field . Table XII.C - 1 — Potentially Regulated Categories and Entities a Category NAICS

Codeb Examples of Potentially Regulated Entities Industry 221112 Fossil fuel
- fired electric utility steam generating units. Federal Government 221112 c Fossil fuel
- fired electric utility steam generating units owned by the federal government. State/Local / Tribal Government 221112 c Fossil fuel
- fired electric utility steam generating units owned by municipalities. 921150 Fossil fuel
- fired electric utility steam

generating un its in Indian Country.

a Include NAICS categories for source categories that own and operate electric generating units only. b North American Industry Classification System. c Federal, state, or local government
- owned and operated establishments are clas sified according to the activity in which they are engaged. After considering the economic impacts of this proposed rule on small entities, EPA is certifying that this action will not have a significant economic impact on a substantial number of small ent ities. This certification is based on the economic impact of this proposed action to627

all affected small entities across all industries affected. EPA has assessed the potential impact of this action on small entities and found that approximately 550 of the estimated 4,700 EGUs potentially affected by today’s proposal are owned by the 81 potentially affected small entities identified by EPA’s analysis . EPA estimates that 30 of the 81 identified small entities will have annualized costs greater than 1 perce nt of their revenues, and the other 51 are projected to incur costs less than 1 percent of revenues. While there are costs greater than 1 percent of revenues for a number of small entities, EPA is certifying No SISNOSE for several reasons. First, of the 30 entities projected to have costs greater than 1 percent of revenues, around 75 percent of them operate in cost of service regions and would generally be able to pass any increased costs along to rate
-payers. This is one of the primary reasons given in the Regulatory Impact Assessment for the Final Clean Air Interstate Rule ( EPA- 452/R

- 05
- 002 March 2005) that supported EPA’s “No SISNOSE ” certification in the final CAIR FIP rule on April 28, 2006 (71 FR 25366) . Furthermore, of the approximately 550 units identified by EPA as being potentially owned by small entities, approximately two
- thirds of the units that have higher costs are not expected to make operational changes as a628

result of this rule (e.g . , install control equipment or switch fuels). Their inc reased costs are largely due to increased cost of the fuel they would be expected to use whether or not they had to comply with the proposed rule. Further, increased fuel costs are often passed through to rate -payers as common practice in many areas of th e United States due to fuel adder arrangements instituted by state public utility commissions. In addition, EPA’s decision to exclude units smaller than 25 MWe has already significantly reduced the burden on small entities. Hence, EPA has conclude d that there is no SISNOSE for this rule . For more information on the small entity impacts associated with the proposed rule, please refer to the Economic Impact and Small Business Analyses in the public docket. These analyses can be found in the Regul atory Impa ct Analysis for this proposed rule. Finally, although EPA believes that the proposed rule would not have a significant economic impact on a substantial number of small entities, EPA plans to take steps to conduct meetings with industry trade associations to discuss regulatory options and ensure that the burdens imposed on small entities are minimal.629 We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts. D. Unfunded Mandates Reform Act of 1995 Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531
- 1538, requires f ederal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on s tate, local, and tribal governments and the private sector. This rule contains a Federal mandate that may result in expenditures of $100 million or more for s tate, local, and tribal governments, in the aggregate, or the private sector in any one year. Accordingly, EPA has prepar ed under section 202 of the UMRA a written statement which is summarized later . Consistent with section 205, EPA has identified and considered a reasonable number of regulatory alter natives. In today’s action, EPA has included three remedy options that i t considered when developing this proposed rule: (1) the proposed remedy of State Budgets/Limited Trading, (2) State Budgets/Intrastate Trading, and (3) Direct Controls. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost - effective or least burdensome alternative if the Administrator publishes with630

the final rule an explanation why that alternative was not adopted. EPA examined the potential economic impacts on state and municipality
- owned entities associated wi th this rulemaking based on assumptions of how the affected states will implement control measures to meet their emissions. Although EPA does not conclude that the requirements of the UMRA apply to the Transport Rule, these impacts have been calculated to provide additional understanding of the nature of potential impacts and additional information. According to EPA’s analysis, o f the 84 government entities considered in this analysis and the 482 government entities in the Transport Rule region that are included in EPA’s modeling, 2 7 may experience compliance costs in excess of 1 percent of revenues in 2014, based on our assumptions of how the affected states implement control measures to meet their emissions budgets as set forth in this rulemaking. Government entities projected to experience compliance costs in excess of 1 percent of revenues have some potential for significant impact resulting from implementation of the Transport Rule. However, as noted previously , it is EPA ’ s position that because thes e government entities can pass on their costs of compliance631

to rate -payers, they will not be significantly affected. Furthermore, the decision to include only units greater than 25 MW in size exempts 380 government entities that would otherwise be potenti ally affected by the Transport Rule. For more information on the impacts estimated for this analysis, please refer to the RIA for this proposed rule. In addition, before EPA establishes any regulatory requirements that may significantly or uniquely af fect small governments, including t ribal governments, it must have developed under section 203 of the UMRA, a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant f ederal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. Cons istent with the intergovernmental consultation provisions of section 204 of the UMRA , EPA has initiated consultations with governmental entities affected by this rule. The EPA has determined that this rule contains a Federal mandate that may result in expenditures of $100632

million or more in 1 year. EPA has determined that this rule contains no regulatory requirements that might significantly or uniquely affect small governments and that development of a small government plan under section 203 of the Act is not required. The costs of compliance will be borne predominately by sources in the private sector although a small number of sources owned by s tate and local governments may also be impacted. The requirements in this action do not distinguish EGUs ba sed on ownership, either for those units that are included within the scope of the rule or for those units that are exempted by the generating capacity cut
- off. Therefore, this rule is not subject to the requirements of section 203 of UMRA because it cont ains no regulatory requirements that might significantly or uniquely affect small governments. E. Executive Order 13132: Federalism This proposed rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The proposed rule primarily affects private industry, and does not impose significant economic costs on s tate or local633

governments. Thus, Executive Order 13132 does not apply to the proposed rule. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA will specifically solicit comment on the proposed rule from s tate and local officials. F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments This action does not have tribal implica tions, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have substantial direct effects on tribal governments, on the relationship between the Federal government and Indian tribes, or on the distribution of power and resp onsibilities between the f ederal government and Indian tribes, as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to the final rule. G. Executive Order 13045: Protection of Children from Environmental Health and Safety Ris ks EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5
- 501 of the Order has the potential634

to influence the regulati on. This action is not subject to Executive Order 13045 because it does not involve decisions on environmental health or safety risks that may disproportionately affect children. The EPA believes that the emissions reductions from the strategies in this rule will further improve air quality and will further improve children’s health. H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use Executive Order 13211 (66 FR 28355, May 22, 2001) provides that agencies sha ll prepare and submit to the Administrator of the Office of Regulatory Affairs, OMB, a Statement of Energy Effects for certain actions identified as “significant energy actions.” Section 4(b) of Executive Order 13211 defines “significant energy action” as “any action by an agency (normally published in the Federal Register ) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1) (i) that is a significant regulatory action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the635

Adminis trator of the Office of Information and Regulatory Affairs as a significant energy action.” This proposed rule is a significant regulatory action under Executive Order 12866, and this proposed rule may have a significant adverse effect on the supply, dist ribution, or use of energy. Under the provisions of this proposed rule, EPA projects that approximately 1.2 GW of coal
- fired generation may be removed from operation by 20 14 . In practice, however, the units projected to be uneconomic to maintain may be “mothballed,” retired, or kept in service to ensure transmission reliability in certain parts of the grid. These units are predominantly small and infrequently
- used generating units dispersed throughout the area affected by the rule. Assumptions of higher natural gas prices or electricity demand would create a greater incentive to keep these units operational. The EPA projects that the average retail electricity price could increase by less than 2.5 percent in 2012 and 1.5 percent in 2014. This is general ly less of an increase than often occurs with fluctuating fuel prices and other market factors. Related to this, delivered coal prices increase by about 7 percent in 2012 and 4 percent in 2014 as a result of higher demand for lower
- sulfur coals. The EPA also projects that natural gas636

prices will increase by less than 1.7 percent in 2012 and that natural gas use for electricity generation will increase by less than 73 million mcf by 2014 . The price increase is also within the range we regularly see in del ivered natural gas prices. Finally, the EPA projects coal production for use by the power sector, a large component of total coal production, will decrease by 3 million tons in 2012 and 9 million tons in 2014. The EPA does not believe that this rule will have any other impacts that exceed the significance criteria. The EPA believes that a number of features of the proposed rulemaking serve to reduce its impact on energy supply. First, the trading programs in State Budgets/Limited Trading provide consider able flexibility to the power sector and enable industry to comply with the emission reduction requirements in the most cost
- effective manner, thus minimizing overall costs and the ultimate impact on energy supply. Second, the more stringent budgets for S O 2 are set in two phases , providing adequate time for EGUs to install pollution controls . In addition, both the operational flexibility of trading and the ability to bank allowances for future years helps industry plan for and ensure reliability in the el ectrical system. For more637

details concerning energy impacts, see the RIA for the proposed Transport Rule. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Publi c Law No. 104
- 113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency deci des not to use available and applicable voluntary consensus standards. This proposed rule would require all sources to meet the applicable monitoring requirements of 40 CFR part 75. Part 75 already incorporates a number of voluntary consensus standards. Consistent with the Agency’s Performance Based Measurement System (PBMS), part 75 sets forth performance criteria that allow the use of alternative methods to the ones set forth in part 75. The PBMS approach is intended to be more flexible and cost
- effect ive for the regulated638

community; it is also intended to encourage innovation in analytical technology and improved data quality. At this time, EPA is not recommending any revisions to part 75; however, EPA periodically revises the test procedures set fort h in part 75. When EPA revises the test procedures set forth in part 75 in the future, EPA will address the use of any new voluntary consensus standards that are equivalent. Currently, even if a test procedure is not set forth in part 75 EPA is not preclu ding the use of any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the performance criteria specified; however, any alternative methods must be approved through the petition process under 40 CFR 75.66 before they are used . J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low
Income Populations . Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justic e. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate,639

disproportionately high and adverse human health or environmental effects of their programs, policies, and
ac tivities on minority, low
- income , and Tribal populations in the United States. 1. Consideration of Environmental Justice Issues in the Rule Development Process In the rulemaking process EPA consi ders whether there are positive or negative impacts of the action that appear to affect low
- income, minority, or Tribal communities disproportionately, and, regardless of whether a disproportionate effect exists, whether there is a chance for these communi ties to meaningfully participate in the rulemaking process. EPA expects that this rule “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” will provide significant health and environmental benefits to, among o thers, people with asthma, people with heart disease, and people living in ozone or fine particle (PM2.5 ) nonattainment areas . This rule also has the potential to affect the cost structure of the utility industry and could lead to regional shifts in electr icity generation and/or emissions of various pollutants. Therefore we expect this rule to be of interest to many environmental justice communities. EPA’s analysis of the effects of this proposed rule, including information640

on air quality changes and the re sulting health benefits , is presented both in section IX of this preamble and in more detail in the air quality modeling Technical Support Document and the Regulatory Impact Analysis (RIA) for this rule. These documents can be accessed through the rule doc ket No. EPA
-HQ
-OAR
-2009
-0491 and from the main EPA webpage for the rule www.epa.gov/airtransport . This section summarizes the legal basis for this rule, and provides background information on how this rule fits into the larger regulatory strategy for contr olling pollution from the power sector. A summary of the emissions, air quality, and health benefit estimates for this rule then follows. This rule is replacing an earlier rule (the 2005 Clean Air Interstate Rule (CAIR)) that was first vacated and then
remanded to EPA by the U.S. Court of Appeals for the District of Columbia Circuit. CAIR was vacated by the U.S. Court of Appeals for the District of Columbia Circuit in July 2008 in a case known as North Carolina v EPA . In December 2008, the vacatur was alte red to a remand based on the likely environmental harms of vacating the rule and EPA’s stated intent to replace the rule promptly. At the time of the 2008 court ruling, many sources had already begun to install and run emissions control devices or otherwis e alter their operations and had successfully begun641

reducing their emissions. The court decision has led to significant uncertainty among affected sources as to what emission reductions will be required and among states and communities as to what air quali ty benefits will be achieved. By proposing this aggressive replacement rule that meets the legal requirements of the Clean Air Act (CAA) as interpreted by the Court in the North Carolina decision promptly, EPA is both maximizing the likelihood that the goa ls of the CAA will be met , and helping communities receive the air quality benefits they need as quickly as possible by minimizing the chance that any emission reductions achieved under CAIR would be lost . It is important to note that CAA § 110(a)(2)(d), which addresses transport of criteria pollutants between states and is the authority for this rule, is only one of many provisions of the CAA that provide EPA, states, and local governments with authorities to reduce exposure to ozone and PM2.5 in communiti es. These legal authorities work together to reduce exposure to these pollutants in communities, including environmental justice communities, and provide substantial health benefits to both the general public and sensitive sub
-populations. T oday’s propose d rule is one of a group of regulatory actions that EPA will take over the next several years to642

respond to statutory and judicial mandates that will reduce exposure to ozone and PM2.5 , as well as to other pollutants , from power plants and other sources . T o the extent that EPA has the legal authority to do so while fulfilling its obligations under the CAA and other relevant statues, we will also coordinate these utility
- related air pollution rules with upcoming regulations for the power sector from EPA’s Of fice of Water (OW) and its Office of Resource Conservation and Recovery (ORCR). The primary actions are outlined below and presented in more detail in section III.E of this preamble . Beyond today’s action and any additional efforts undertaken in response t o comment, other rules that will drive the creation of a clean, efficient and completely modern power sector include : CAA section 112 (d) standards (one of which is often referred to as a Maximum Achievable Control Technology ( MACT) standard) to reduce emi ssions of air toxics, including mercury, and particles from coal
- and oil
- fired power plants; new National Ambient Air Quality Standards (NAAQS) for ozone, PM2.5 , sulfur di oxide, and nitrogen oxides; potentially one or more additional rules eliminating inte rstate transport of emissions that contribute significantly to non attainment and maintenance areas for the new ozone and PM2.5 NAAQS as necessary;643

revisions to the New Source Performance Standards (NSPS) for steam electric generating units ; and best available retrofit technology (BART) requirements and other requirements that address visibility and regional haze . Within the planning and investment horizon for compliance with these rules, EPA very likely will be compelled to respond to a pending petition to set standards for the emissions of greenhouse gases (GHGs) from steam electric generating units under the New Source Performance Standard program. Furthermore, as set forth in the recently promulgated reinterpretation of the Johnson Memo, beginning in 201 1 new and modified sources of GHG emissions, including EGUs, will be subject to permits under the Prevention of Significant Deterioration program requiring them to adopt Best Available Control Technology for their GHGs. Finally, EPA will pursue energy eff iciency improvements in the use of electricity throughout the economy , along with other federal agencies, states and other groups , which will contribute to additional environmental and public health improvements that the Agency wants to provide while lower ing the costs of realizing those improvements. Together, t hese rules and actions will have substantial and long
- term e ffect s on both the U.S. power644

industry and on communities currently breathing dirty air . Therefore, we anticipate significant interest i n many, if not most, of these actions from environmental justice communities, among many others. EPA intends to provide multiple opportunities for comment on these actions, including during the comment process for this rule, and encourages environmental ju stice communities to review and comment on them. 2. Potential Environmental and Public Health Impacts to Vulnerable Populations There are several considerations to take into account when assessing the effects of this proposed rule on minority, low
- income , and Tribal populations. These include: amount of emissions reductions and where they take place (including any potential for areas of increased emissions); the changes in ambient concentrations across the affected area; and the health benefits expected f rom the rules. Emission reductions . This proposed rule will reduce exposure to PM2.5 and ozone pollution in most eastern states by reducing interstate transport of these pollutants and their chemical precursors (sulfur dioxide (SO 2 ) and nitrogen oxides (NO x )). This rule has the effect of reducing emissions of these pollutants that affect the most
-645

contaminated areas (i.e. areas that are not meeting the 1997 and 2006 ozone and PM2.5 National Ambient Air Quality Standards (NAAQS)). This rule separately identif ies both
non attainment areas and maintenance areas ( maintenance
areas are those that currently meet the NAAQS but that, based on past data, are in danger of exceeding the standards in the future). This approach of requiring emission reductions to protect maintenance areas as well as nonattainment areas reduces the likelihood that any areas close to the level of the standard will exceed the current health
-based standards in the future. Ozone and PM2.5 concentrations in both nonattainment and maintenance are as identified in this rule are the result of both local emissions and long
- range transport of pollution. This rule requires upwind states to reduce or eliminate their significant contribution to nonattainment or maintenance problems in downwind states. Even when the significant contributions of upwind states are fully eliminated, additional emissions reductions within the nonattainment area and/or the downwind state will be needed for some areas to attain and maintain the NAAQS. The proposed remedy optio n for this rule would use a limited emissions trading mechanism among power plants to achieve significant emission reductions in states covered646

by the rule. EPA recognizes that many environmental justice communities have voiced concerns about emissions tra ding and any resulting potential for any emissions increases in any location . This proposed rule uses EPA’s authority in CAA §110(a)(2)(d) to require states to eliminate emissions from power plants in their state that contribute significantly to downwind PM2.5 or ozone non attainment or maintenance areas. EPA’s pr oposed mechanism for achieving these emission reductions is to use a tightly constrained trading program that requires a strict emission ceiling in each state while allowing a limited ability to sh ift emissions between facilities or states. This approach ensures that emissions in each state that significantly contribute to downwind non attainment or maintenance areas are controlled, while allowing power companies to adjust generation based on fluctua tions in electricity demand, weather, availability of low
- emitting power sources (e.g. temporary shut
- down of a nuclear power plant for maintenance or repairs), or other unanticipated factors affecting the interconnected electricity grid. Any emissions ab ove the state’s allocated level must be offset by emission reductions from another state in the region below that state’s budget or by using extra “banked ”647

allowance s from earlier years. All sources must hold enough allowances to cover their emissions; the refore, if they emit more than their allocation they must buy allowances from another source that emitted less than its allocation. PM2.5 and ozone pollution from power plants have both local and regional components: part of the pollution in a given locati on – even in locations near emissions sources

– is due to emissions from nearby sources and part is due to emissions that travel hundreds of miles and mix with emissions from other sources. Therefore, in many instances the exact location of the upwind redu ctions does not affect the levels of air pollution downwind. It is important to recognize that the section of the Clean Air Act providing authority for this rule, 110(a)(2)(D), unlike some other provisions, does not dictate levels of control for particular facilities. None of EPA’s alternatives within this proposal can ensure there will be no emission increases at any facility. Under the direct control alternative, the emission rate for each facility is reduced but each facility could emit more by increasin g their power output in order to meet electricity reliability or other goals. Under the intrastate trading option, state emissions must stay constant but individual facilities within each state could increase their emissions648

as long as another facility in the state had decreased theirs. By strictly setting state budgets to eliminate significant contributions to non
- attainment and maintenance areas that EPA has identified in today’s action, by limiting the amount of interstate trading possible and by requiri ng any emissions above the level of the allocations to be offset by emission decreases elsewhere in the region, the proposed remedy option s reduce ambient concentrations where they are most needed. EPA’s emissions modeling data indicate that nationwide SO 2 emissions from electric generating units (EGUs) will be approximately 6.4 million tons (60%) lower in 2014 than they were in 2005 ( which is the year that the Clean Air In terstate Rule was finalized). Emissions would also decrease when compared to the base case ( the base case estimates of SO 2 emissions in 2014 in the absence of this proposed rule or the Clean Air Interstate Rule it is replacing ). SO 2 emissions under this proposed rule are projected to be approximately 4. 4 million tons (50%) lower than they would have been in 2014 in the base case (i.e. without this rule ) . EPA’s modeling does project that some states not covered by one or more aspects of the program may experience increases of SO 2 emissions (i.e., their emissions649

are greater in the control c ase modeling than in the base case modeling). These emission increases are the result of forecasted changes in operation of units outside of the controlled region (due to the interconnected nature of the utility grid or influence of the rule on the market for lower sulfur coal) . As shown in Table IV.D.6 , Arkansas, Mississippi, North Dakota, South Dakota, and Texas all exhibit 2012 SO 2 emissions increases over the base case of more than 5,000 tons. Texas is projected to have by far the largest increase (136, 000 tons), while the other states’ increases ranges from 6,000 to 32,000 tons. Further analysis with the simplified air quality assessment tool indicates that these projected increases in the Texas SO 2 emissions would increase Texas’s contribution to an amount that would exceed the 0.15 μg/m3 threshold for annual PM2.5 . For this reason, EPA requests comment on whether Texas should be included in the program as a group 2 state. For additional details, see section IV.D of this preamble. With the exception noted above, EPA is not proposing for the SO 2 portion of this rule to cover the states where SO 2 emissions are projected to increase because EPA has not found, at this time, that they contribute significantly to nonattainment or interfere with maintenance of the PM2.5 NAAQS in downwind areas . EPA’s authority under650

§110 (a)(2)(d)(i)(I ) is limited to addressing any such significant contribution and interference with maintenance . EPA anticipates that additional rulemakings affecting utilities that will be proposed soon, su ch as the CAA Section 112(d) standards , would apply nationwide and result in significant additional SO 2 reductions. EPA’s emissions modeling data indicates that nationwide ozone season NO x emissions from EGUs will be approximately 400,000 tons ( 30 %) lower in 2014 than they were in 2005 (before implementation of the Clean Air Interstate Rule). Emissions would also decrease compared to the base case. Ozone season NO x emissions from EGUs under this proposed rule are projected to b e approximately 150,000 tons ( 15 %) lower than they would have been in 2014 in the base case (i.e. without this rule) . EPA anticipates that additional upcoming actions , and likely additional interstate transport reductions to help states attain the proposed 2010 ozone NAAQS , will re sult in significant additional NO x reductions. EPA anticipates that this proposed action will significantly reduce, but not eliminate, the number of nonattainment and maintenance areas for the 1997 ozone and PM2.5 and 2006 PM2.5 NAAQS. Table IX
- 1 lists the changes in number of nonattainment sites. Most of these sites are651

located in urban areas. A single nonattainment area usually contains multiple monitoring sites; therefore there are more nonattainment sites than nonattainment counties or areas. As discussed i n detail in section IV.D of this preamble, where this proposal does not fully quantify all of the significant contribution and interference with maintenance, EPA intends to address these additional requirements quickly. To the extent possible, EPA will
supplement this proposed notice with additional information so that we can provide downwind states with all the certainty about upwind emission reductions they need to address their own local nonattainment concerns. In addition, as stated above, elimination of these nonattainment areas may require both local and regional emission reductions and this proposed action seeks only to address the regional transport component. As a result of these SO 2 and NO x reductions, EPA’s air quality modeling indicates that con centrations of fine particles will decline throughout the eastern U.S. and in all the states affected by this rule. These reductions are largest in the area of the Ohio River valley and neighboring states and extend east through New England, west to Texas, south to Florida, and north through the Great Lakes states. “Border” states immediately outside the652

transport region are also predicted to see reductions in air concentrations, even though emissions increase in some of these states. This is because concen trations of fine particles in most locations are composed of both local emissions and those transported over hundreds of miles and emission reductions far away can cause significant improvements in local air quality . The modeling suggests also that there may be some small increases in PM2.5 near locations in the western U.S. where SO 2 emissions are forecast to increase. These increases are small compared to the reductions predicted to take place in the eastern U.S. The increases are due to the regional na ture of this rule (i.e. these states are not covered because sources in these states have not been found to contribute significantly to downwind nonattainment or maintenance areas) and the national nature of both coal markets and the Acid Rain Program allowance market. They are not the result of any particular type of remedy option (e.g. trading). EPA anticipates that future rulemakings, such as CAA section 112(d) standards and anticipated revisions to the 2006 fine particulate standards, are likely to redu ce emissions in the areas not covered by this rule.653 EPA’s air quality modeling also indicates that concentrations of ozone will decline in much of the eastern U.S. These reductions are largest along much of the Gulf Coast and in Florida and in a region enc ompassing western Wisconsin, Iowa, Kansas, Missouri, Arkansas, and northeastern Oklahoma. These areas with the largest reductions are roughly the area immediately outside the boundaries of the NO x SIP Call region. States in the SIP Call region were require d to make significant reductions in NO x beginning in 2003 and these emission reductions are included in the baseline modeling for this proposed Transport Rule and therefore not captured as additional benefits of this rulemaking. As is common when modeling many NO x control strategies, the air quality modeling for this proposed rule also suggests there may be a few small, localized areas in the Eastern U.S. where there are small increases in ozone concentrations. These generally small increases are a result of reductions in NO x emissions in these local areas; they do not appear to represent a lack of NO x emissions reductions or be the result of any specific emission control strategy (e.g. any type of trading). Rather, this phenomenon can result from complex a tmospheric chemistry reactions taking place among chemical constituents of air654

pollution in these areas. Due to the complex photochemistry of ozone production, NO x emissions lead to both the formation and destruction of ozone, depending on the relative quantities of NO x , volatile organic compounds , and ozone formation catalysts. In the 2014 base case, NO x emissions from sources in a few locations act to “quench” (i.e., lower) ozone compared to ozone concent rations in surrounding areas. The application of NO x controls in these
areas reduces this quenching effect , thereby increasing ozone to levels generally on par with those of the surrounding area. In this case it is uncertain whether the structure of the model itself is potentially exacerbating the spatial extent or magnitude of any ozone increases which might actually occur as a result of this rule. It should be noted that these same NO x emission reductions that might be causing extremely localized ozone increases are certainly causing larger, more widespr ead improvements in ozone concentrations in downwind areas. Finally, as stated above, it is important to note that EPA intends to promulgate additional rules over the next few years that will further reduce concentrations of ozone and PM2.5 and that the fe deral government and the states can and do use many different legal authorities to limit exposure to
ozone.655 Health benefits . This rule reduces concentrations of PM2.5 and ozone pollution, exposure to which can cause , or contribute to , adverse health effe cts including premature mortality and many types of heart and lung diseases that affect many minority and low
- income individuals , and Tribal communities . PM2.5 and ozone are particularly (but not exclusively) harmful to children, the elderly, and people wi th existing heart and lung diseases, including asthma. Exposure to these pollutants can cause premature death and trigger heart attacks, asthma attacks in those with asthma, chronic and acute bronchitis, emergency room visits and hospitalizations, as well as milder illnesses that keep children home from school and adults home from work. High rates of both heart disease and asthma are a cause for concern in many environmental justice communities, making these populations more susceptible to air pollution hea lth impacts. In addition, many individuals in these communities also lack access to high quality health care to treat these illnesses. We estimate that in 2014 the PM
- related annual benefits of the proposed remedy option include approximately 14,000 to 36 ,000 fewer premature mortalities, 9,200 fewer cases of chronic bronchitis, 22,000 fewer non
fatal heart attacks, 11,000 fewer hospitalizations (for656

respiratory and cardiovascular disease combined), 10 million fewer days of restricted activity due to respir atory illness and approximately 1.8 million fewer lost work days. We also estimate substantial health improvements for children in the form of fewer cases of upper and lower respiratory illness, acute bronchitis, and asthma attacks. Ozone health
- related be nefits are expected to occur during the summer ozone season (usually ranging from May to September in the Eastern U.S.). Based upon modeling for 2014, annual ozone related health benefits are expected to include between 50 and 230 fewer premature mortaliti es, 690 fewer hospital admissions for respiratory illnesses, 230 fewer emergency room admissions for asthma, 300,000 fewer days with restricted activity levels, and 110,000 fewer days where children are absent from school due to illnesses. When adding the PM and ozone
- related mortalities together, we find that the proposed remedy option for this rule will yield between 14,000 and 36,000 fewer premature mortalities. EPA has also estimated the benefits of the alternate remedies in this proposal using a benefi t -per - ton estimation approach and found they would provide similar benefits.657 It should be noted that, as discussed in the RIA for this action, there are other benefits to the emission reductions discussed here, such as improved visibility and, indirectly, reduced mercury deposition. Additional benefits of reducing emissions of SO 2 include reduced acidification of lakes and streams, and reduced mercury methylation; additional benefits of NO x reductions include reduced acidification of lakes and streams and reduced coastal eutrophication. Conversely, it is possible that the modest increases in emissions modeled for this rule in some western areas could result in limited increases of one or more of these effects in these locations. 3. Meaningful Public Partic ipation As EPA began considering approaches to address the court remand of the 2005 Clean Air Interstate Rule, the agency also began gathering input from a larger range of stakeholders. In the spring of 2009, EPA held a series of listening sessions to gather information and perspectives from stakeholders prior to the formal start of the rulemaking process. These stakeholders included a number of environmental groups who requested that EPA consider several potential environmental justice issues during development of this rule. In addition, many environmental justice organizations were represented at a November 2009658

EPA- Health and Human S ervices White House Stakeholder Briefing entitled “The Public Health Benefits of Energy Reform” in which EPA discussed our i ntention to propose this rule in the spring of 2010 and participants had the opportunity to respond. Finally, EPA notified tribes of our intent to propose this rule in the fall of 2009 during a regularly scheduled meeting to update the National Tribal Air Association members of upcoming EPA policies and regulations and to receive input from them on the effe cts of these efforts in Indian c ountry. These were not opportunities for stakeholders to comment on the specifics of this proposal, as they took place pr ior to the development of this proposal, but they provided valuable information that EPA used in developing this proposal. Upon proposal of this action, the Agency will begin an outreach effort with environmental justice communities, the public, the regula ted community, state air regulators, and others to (1) describe the Transport Rule proposal, (2) provide information on the 2011 CAA Section 112 (d) and other upcoming EPA rulemakings affecting the power sector, and (3) listen to comments from stakeholders . The intent will be to inform all stakeholders of the industry’s obligations and opportunities for the industry to use investments in SO 2 and NO x reductions to help smooth659

transition to the CAA Section 112(d) standards compliance in late 2014. EPA intends to continue these efforts over time as more information becomes available in the development of the various rulemakings under development for the power sector. During the comment period for this proposed rule, EPA intends to reach out specifically to envi ronmental justice communities and organizations to notify them of the opportunity to provide comments on this rule and to solicit their comments on both this rule and the upcoming actions described above and in section III.E . EPA will hold public hearings on this rule ; see the information at the very beginning of this preamble for locations, times and dates. Comments can also be submitted in writing or electronically by following the instructions at the beginning of this preamble. 4. Summary EPA believes th at the vast majority of communities and individuals in areas covered by this rule, including numerous low
- income, minority, and Tribal communities in both rural areas and inner cities in the East, will see significant improvements in air quality and result ing improvements in health. EPA also recognizes that there is the potential for a number of communities or individuals660

outside the region covered by this rule to experience slightly worse air quality as an indirect result of emission reductions required under this proposal. EPA requests comment on the impacts of this proposed action on low income, minority, and Tribal communities. EPA will further analyze environmental justice issues related to the impacts of the rule on those communities based both on additional data that may be developed and on comments on those issues prior to final action on this rule.661

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___________________________________ Dated:

___________________________________ Lisa P. Jackson, Administrator.