## Monday,

August 2, 2010



# Part II



# Environmental Protection Agency

40 CFR Parts 51, 52, 72, et al.
Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone; Proposed Rule


### 45210 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

**ENVIRONMENTAL PROTECTION**
**AGENCY**

**40 CFR Parts 51, 52, 72, 78, and 97**

**[EPA–HQ–OAR–2009–0491; FRL–9174–9]**

**RIN 2060–AP50**

**Federal Implementation Plans To Reduce Interstate Transport of Fine** 
**Particulate Matter and Ozone**

**AGENCY :**  Environmental Protection Agency (EPA).

**ACTION :**  Proposed rule.

**SUMMARY :**  EPA is proposing to limit the interstate transport of emissions of nitrogen oxides (NO X ) and sulfur dioxide (SO 2 ). In this action, EPA is proposing to both identify and limit
emissions within 32 states in the eastern United States that affect the ability of
downwind states to attain and maintain compliance with the 1997 and 2006 fine particulate matter (PM 2.5 ) national ambient air quality standards (NAAQS) and the 1997 ozone NAAQS. EPA 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 federal 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 PM 2.5 NAAQS by 2014 or earlier. To the extent the proposed FIPs do not fully address all significant transport, EPA is committed to assuring that any
additional reductions needed are addressed quickly. EPA takes comments on ways this proposal could achieve
additional NO X reductions and additional actions including other rulemakings that EPA could undertake to achieve any additional reductions
needed.

**DATES :**  Comments . Comments must be received on or before October 1, 2010.

Public Hearing: Three public hearings
will be held before the end of the comment period. The dates, times and locations will be announced separately.
Please refer to **SUPPLEMENTARY**

**INFORMATION** for additional information on the comment period and the public hearings.

**ADDRESSES :**  Submit your comments, identified by Docket ID No. EPA–HQ– OAR–2009–0491 by one of the following
methods:

• http://www.regulations.gov . Follow the online instructions for submitting
comments. Attention Docket ID No. EPA–HQ–OAR–2009–0491. • 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–OAR–2009–

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. In addition, please mail a copy of your comments on the information collection provisions 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 Constitution 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 information.

Instructions. Direct your comments to Docket ID No. EPA–HQ–OAR–2009– 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 http:// 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 http:// www.regulations.gov or e-mail. The http://www.regulations.gov Web site 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. If you send an e-mail comment directly to EPA without going through http:// 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 special 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 http:// www.epa.gov/epahome/dockets.htm

.

Docket . All documents in the docket
are listed in the http:// www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g. , CBI or other
information whose disclosure 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 http:// 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 Public 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 Quality 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. ARP Acid Rain Program BART Best Available Retrofit Technology BACT Best Available Control Technology
CAA or Act Clean Air Act
CAIR Clean Air Interstate Rule
CBI Confidential Business Information CFR Code of Federal Regulations EGU Electric Generating Unit FERC Federal Energy Regulatory

Commission
FGD Flue Gas Desulfurization FIP Federal Implementation Plan FR Federal Register EPA U.S. Environmental Protection Agency
GHG Greenhouse Gas Hg Mercury IPM Integrated Planning Model
lb/mmbtu Pounds Per Million British

Thermal Unit

μ g/m 3 Micrograms Per Cubic Meter


### 45211 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

NAAQS National Ambient Air Quality

Standards

NO X Nitrogen Oxides
NSPS New Source Performance Standard OTAG Ozone Transport Assessment Group PUC Public Utility Commission SNCR Selective Non-catalytic Reduction SCR Selective Catalytic Reduction SIP State Implementation Plan

PM 2.5 Fine Particulate Matter, Less Than 2.5

Micrometers

PM 10 Fine and Coarse Particulate Matter,

Less Than 10 Micrometers
PM Particulate Matter RIA Regulatory Impact Analysis

SO 2 Sulfur Dioxide

SO X Sulfur Oxides, Including 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.

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. Following signature by the EPA Administrator, a copy of this action will be posted on the transport
rule Web site http://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 http:// 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.

2. Tips for preparing your comments

. When submitting 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 your 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 hearings?

The EPA will hold three public hearings on this proposal. The dates, times and locations of the pubic hearings will be announced separately. 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 will be included in the rulemaking docket. If you would like to present oral testimony at one of the hearings, please notify Ms. Pamela S. Long, Air Quality Policy Division (C504–03), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541–0641; 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 hearings. For updates and additional information on the public hearings, please check EPA’s website for this rulemaking, http://www.epa.gov/ airtransport . The public hearings 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 will 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 and supporting information presented at the public hearings.

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 Proposed Rule and Background A. Summary of Proposed Rule B. Background 1. What is the source of EPA’s authority for

this action? 2. What air quality problems does this

proposal address? 3. Which NAAQS does this proposal

address? 4. EPA Transport Rulemaking History C. What are the goals of this proposed rule? 1. Primary Goals 2. Key Guiding Principles D. Why does this proposed rule focus on

the eastern half of the United States? E. Anticipated Rules Affecting Power

Sector IV. Defining ‘‘ Significant Contribution ’’ and

‘‘ Interference With Maintenance ’’ A. Background 1. Approach Used in NO X SIP Call and

CAIR 2. Judicial Opinions 3. Overview of Proposed Approach B. Overview of Approach To Identify

Contributing Upwind States 1. Background 2. Approach for Proposed Rule C. Air Quality Modeling Approach and

Results 1. What air quality modeling platform did

EPA use? 2. How did EPA project future

nonattainment and maintenance for
annual PM 2.5 , 24-Hour PM 2.5 , and 8-hour

ozone?
3. How did EPA assess interstate

contributions to nonattainment and

maintenance?


### 45212 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

1 In the context of the jurisdictions covered by this proposed rule, EPA uses the term ‘‘ states ’’ to include the District of Columbia. 4. What are the estimated interstate

contributions to annual PM 2.5 , 24-hour

PM 2.5 , and 8-hour ozone nonattainment
and maintenance? D. Proposed Methodology To Quantify

Emissions That Significantly Contribute
or Interfere With Maintenance 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 State

Emissions Budgets for EGUs 2. Defining Ozone Season NO X State

Emissions Budgets for EGUs F. Emissions Reductions Requirements

Including Variability 1. Variability 2. State Budgets With Variability Limits 3. Summary of Emissions Reductions

Across All Covered States G. How the Proposed Approach Is

Consistent With Judicial Opinions Interpreting Section 110(a)(2)(D)(i)(I) of
the Clean Air Act H. Alternative Approaches Evaluated But

Not Proposed V. Proposed Emissions Control Requirements

A. Pollutants Included in This Proposal B. Source Categories 1. Propose To Control Power Sector

Emissions 2. Other Source Categories Are Not

Included C. Timing of Proposed Emissions

Reductions Requirements 1. Date for Prohibiting Emissions That

Significantly Contribute or Interfere With
Maintenance of the PM 2.5 NAAQS 2. Date for Prohibiting Emissions That

Significantly Contribute or Interfere With Maintenance of the 1997 Ozone NAAQS 3. Reductions Required by 2012 To Ensure

That Significant Contribution and
Interference With Maintenance Are Eliminated as Expeditiously as
Practicable 4. How Compliance Deadlines Address the

Court’s Concern About Timing
5. EPA Will Consider Additional

Reductions in Pollution Transport To Assist in Meeting Any Revised or New NAAQS D. Implementing Emission Reduction

Requirements 1. Approach Taken in NO X SIP Call and

CAIR 2. Judicial Opinions 3. Remedy Options Overview 4. State Budgets/Limited Trading Proposed

Remedy 5. State Budgets/Intrastate Trading Remedy

Option 6. Direct Control Remedy Option E. Projected Costs and Emissions for Each

Remedy Option 1. State Budgets/Limited Trading 2. State Budgets/Intrastate Trading
3. Direct Control 4. State-Level Emissions ProjectionsF. Transition From the CAIR Cap-andTrade Programs to Proposed Programs 1. Sunsetting of CAIR, CAIR SIPs, and

CAIR FIPs 2. Change in States Covered 3. Applicability, CAIR Opt-Ins and NO X

SIP Call Units 4. Early Reduction Provisions 5. Source Monitoring and Reporting G. Interactions With Existing Title IV

Program and NO X SIP Call
1. Title IV Interactions

2. NO X SIP Call Interactions
VI. Stakeholder Outreach VII. State Implementation Plan Submissions

A. Section 110(a)(2)(D)(i) SIPs for the 1997

Ozone and PM 2.5 NAAQS B. Section 110(a)(2)(D)(i) SIPs for the 2006

PM 2.5 NAAQS C. Transport Rule SIPs VIII. Permitting

A. Title V Permitting

B. New Source Review IX. What benefits are projected for the proposed rule? A. The Impacts on PM 2.5 and Ozone of the

Proposed SO 2 and NO X 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 benefits compare to the

costs of this proposed rule? G. What are the unquantified and

unmonetized benefits of the transport
rule emissions reductions?
1. What are the benefits of reduced

deposition of sulfur and nitrogen to aquatic, forest, and coastal ecosystems? 2. Ozone Vegetation Effects
3. Other Health or Welfare Disbenefits of

the Transport Rule That Have Not Been Quantified X. Economic Impacts XI. Incorporating End-Use Energy Efficiency Into the Proposed Transport Rule A. Background 1. What is end-use energy efficiency? 2. How does energy efficiency 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? B. Incorporating End-Use Energy Efficiency

Into the Transport Rule 1. Options That Could Be Used To

Incorporate Energy Efficiency Into Allowance Based Programs 2. Why EPA did not propose these options? XII. Statutory and Executive Order Reviews

A. Executive Order 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 From 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 Impacts to Vulnerable Populations 3. Meaningful Public Participation

4. Determination

III. Summary of Proposed Rule and Background

A. Summary of Proposed Rule

CAA section 110(a)(2)(D)(i)(I) requires states to prohibit emissions that contribute significantly to 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 NO X in 32 eastern states contribute significantly
to nonattainment or interfere with
maintenance in one or more downwind states with respect to one or more of three air quality standards—the annual average PM 2.5 NAAQS promulgated in 1997, the 24-hour average PM 2.5 NAAQS promulgated in 2006, and the ozone NAAQS promulgated in 1997. 1 These emissions are transported downwind
either as SO 2 and NO X 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 emissionsreductions in each state through costeffective 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

PM 2.5 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 PM 2.5 NAAQS, this proposal finds that 25 eastern states
have emission reduction responsibilities. The proposed reductions will at least partly eliminate, and subject to further analysis may fully eliminate, these states’ significant
contribution and interference with maintenance for purposes of the 24-hour average PM 2.5 standard. In all, emissions reductions related to interstate transport


### 45213 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

of fine particles would be required in 28

states.

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 ozone 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 information 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
substantial near-term emissions reductions from 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 lower 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 dropped 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, and 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 the 1997 PM 2.5 and ozone standards and take major strides toward helping states address
nonattainment with the 2006 24-hour average PM 2.5 standard. See Table III.A– 1 for proposed list of covered states.

EPA is committed to fulfilling its responsibility to ensure that downwind states receive the relief from upwind emissions guaranteed under CAA section 110(a)(2)(D) For the 24-hour

PM 2.5 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

PM 2.5 results could lead to a number of possible outcomes; EPA cannot judge
the relative likelihood of these outcomes at this time. 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 PM 2.5 standard. To that end, EPA is expeditiously proceeding with
examination 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 ozone 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 quality 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 developing supplemental information to
consider NO X sources beyond EGUs 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 benefits associated with this proposed rule. Thus, EPA intends to proceed with additional rulemaking to address fully the residual significant contribution to
nonattainment and 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-fired 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 January established improved air quality as an Agency priority and announced plans to promote a cleaner and more efficient power sector and have strong but achievable reduction goals for SO 2 , NO X , 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.

Ongoing reviews of the ozone and

PM 2.5 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 proposal 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 interstate 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 Columbia to adopt and
submit revisions to their State Implementation Plans (SIPs) to
eliminate SO 2 and NO X emissions that contribute significantly to downwind
nonattainment of the PM 2.5 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 reductions requirements established by CAIR until states have approved SIPs to achieve the reductions. In July 2008, the DC Circuit
Court found CAIR and the CAIR FIPs
unlawful. North Carolina v. EPA , 531 F.3d 896 (DC Cir. 2008). The Court’s original decision vacated CAIR. Id. at 929–30. However, the Court subsequently remanded CAIR to 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 (DC Cir. 2008). The CAIR requirements are correctly in place and the CAIR’s regional control programs are operating


### 45214 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

2 For the 10 states discussed above for which EPA has only quantified a minimum amount of
emissions reductions needed to make measurable 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 reductions requirements in this rule, as May through September. We recognize that this ozone season for regulatory requirements differs from the official state-specific monitoring season. 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 Carolina v. EPA and address the flaws in CAIR identified by the Court therein. Among other things, the proposal relies on detailed, bottom-up scientific and technical analyses, introduces a state-specific methodology for identifying significant contribution
to nonattainment and interference with maintenance, and proposes remedy options to ensure that all necessary
reductions are achieved in the covered

states.

In this 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 sections III and VII in this preamble and described in greater detail in two separate Federal Register notices published on April 25, 2005 (70 FR 21147) and June 9, 2010 (75 FR 32673), EPA has determined, or proposed to determine, that the 32 states covered by this proposal either have not submitted SIPs adequate to meet the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 and 2006 PM 2.5 NAAQS and the 1997 ozone NAAQS, or that the SIP provisions currently in place are not adequate to meet those requirements.

As described in section IV in thispreamble, EPA is proposing a statespecific 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. Theproposed methodology uses statespecific 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. If a state’s contribution does not exceed those thresholds, its contribution is found to be insignificant and it is no longer considered in the analysis. If a state’s contribution 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 maintenance. 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 PM 2.5 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 significant
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’s 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 NO X budgets for each state covered for the 24-hour and/or annual average

PM 2.5 NAAQS. EPA proposes an ozone

season 3 NO X budget for each state covered for the ozone NAAQS.

EPA recognizes that baseline emissions from a state can be affected by changing weather patterns, demand growth, or 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. See section V for a
detailed discussion of the assurance provisions. The small amount of variability allowed takes into account the inherent variability in baseline emissions. Section IV in this preamble describes the proposed 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 PM 2.5 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 EPA has not completely quantified total significant contribution
or interference with maintenance with respect to the 2006 PM 2.5 NAAQS in
which case the FIPs would achieve measurable progress towards implementing that requirement.

The emissions 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


### 45215 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

necessary reductions ‘‘ in the state ’’ as required by section 110(a)(2)(D)(i)(I). The proposed FIPs include 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 the 32 covered states. EPA is proposing to regulate these sourcesthrough a program that uses statespecific budgets and allows intrastate and limited interstate trading. EPA is also taking comment on two alternative regulatory options. All options would
achieve the emissions 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 would
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 prohibit interstate trading. The second alternative remedy option, for which EPA also requests comment, would use state-specific budgets and emissions rate
limits. See section V for further discussion of the remedy options.

The proposed remedy option and thefirst alternative, both of which are capand-trade approaches, would use new allowance allocations developed on a
different basis from CAIR. Allowance allocations, like the state budgets described previously, would be developed based on the methodology used by EPA to quantify each state’s significant contribution and interference
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 NO X emissions in the following 25 jurisdictions that contribute significantly to nonattainment in, or interfere with maintenance by, a downwind area with respect to the 24-
hour PM 2.5 NAAQS promulgated in September 2006: Alabama, Connecticut, Delaware, 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.

EPA proposes to require reductions in

SO 2 and NO X emissions in the following 24 jurisdictions that contribute significantly to nonattainment in, or interfere with maintenance by, a downwind area with respect to the
annual PM 2.5 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 ozone 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 Virginia.

As discussed previously, EPA also is proposing FIPs to directly regulate EGU

SO 2 and/or NO X emissions in the 32 covered states. The proposed FIPs would require the 28 jurisdictions covered for purposes of the 24-hour
and/or annual PM 2.5 NAAQS to reduce

SO 2 and NO X 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 maintenance areas. EPA proposes to require that all significant contribution
to nonattainment and interference with
maintenance identified in this action with respect to the PM 2.5 NAAQS be eliminated by 2014 and proposes 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 emissions levels occurs when the requirements of
the CAIR are eliminated. Sources will be required to comply by January 1, 2012 and January 1, 2014 for the first and second phases, respectively. With respect to the 1997 ozone NAAQS, EPA proposes to require an initial phase of

NO X reductions starting in 2012 to
ensure that reductions are made as expeditiously as practicable. Sources will be required to comply by May 1, 2012 and May 1, 2014 for the first and second phases, respectively. EPA has determined, that for many states, these
reductions will be sufficient to eliminate their significant contribution with respect to the 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 lists of
covered state.



### T ABLE 

### III.A–1—L ISTS OF 

### C OVERED 

### S TATES FOR 

### PM 2.5 AND 

### 8-H OUR 

### O ZONE 

### NAAQS

State Covered for 24-hour and/or annual PM 2.5 Covered for 8-hour ozone

Required to reduce SO 2 and NO X Required to reduce ozone Season NO X

Alabama ........................................................................................................................ ................................... X X

Arkansas .......................................................................................................................................................... ............................ X
Connecticut .................................................................................................................... .................................. X X

Delaware ....................................................................................................................... ................................... X X
District of Columbia ........................................................................................................... .............................. X X

Florida ........................................................................................................................ ...................................... X X


### 45216 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 with states in SO 2 group 2. 

### T ABLE 

### III.A–1—L ISTS OF 

### C OVERED 

### S TATES FOR 

### PM 2.5 AND 

### 8-H OUR 

### O ZONE 

### NAAQS—Continued

State Covered for 24-hour and/or annual PM 2.5 Covered for 8-hour ozone

Required to reduce SO 2 and NO X Required to reduce ozone Season NO 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 X

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 accounting 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 PM 2.5 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 28 states. Similarly, for the 26 states covered for the ozone NAAQS there
would be one ozone season NO X tier with uniform stringency across all 26

states.

The proposed stringent SO 2 tier ( ‘‘ group 1 ’’ ) would include Georgia, Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, New York, North 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, Minnesota, 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 NO X reductions in the 28 states covered for
24-hour and/or annual PM 2.5 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
reductions needed to eliminate the portion of significant contribution and
interference with maintenance that EPA has identified in this proposal from these states with respect to the 24-hour

PM 2.5 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 PM 2.5 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

NO X budgets for the 26 states covered for the ozone NAAQS. EPA intends 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


### 45217 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

5 Projected Transport Rule emissions result from individual stae budgets in the proposed approach and include some banking of allowances in 2012

adn use of that bank in 2014. 6 EPA’s base case EGU emissions modeling does
not assume enforceable SO 2 or NO X reductions attributed to the Transport Rule or CAIR. In this base case, a unit with existing SO 2 or NO X 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 IPM Documentation for further information on the base case modeling. 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 more 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 emissions

reductions for EGUs in all states that EPA proposes to cover.



### T ABLE 

### III.A–2—P ROJECTED 

### SO 2 AND 

### NO X 

### EGU E MISSIONS IN 

### C OVERED 

### S TATES 

### W ITH THE 

### T RANSPORT 

### R ULE 5


### C OMPARED TO 

### B ASE 

### C ASE 6 

### W ITHOUT 

### T RANSPORT 

### R ULE 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



### T ABLE 

### III.A–3—P ROJECTED 

### SO 2 AND 

### NO X 

### EGU E MISSIONS IN 

### C OVERED 

### S TATES 

### W ITH THE 

### T RANSPORT 

### R ULE 

### C OMPARED TO 

### 2005 A CTUAL 

### E MISSIONS

[Million tons]

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 emissions reductions shown previously, EPA projects other substantial benefits, as described in section IX in this preamble. Air quality modeling was used to quantify the improvements in PM 2.5 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 PM 2.5 , 24- hour average PM 2.5 , 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 PM 2.5 and 24-hour PM 2.5 , the average reductions are 2.4 micrograms per cubic meter ( μ g/m 3 ) and 4.3 μ g/m 3

, respectively. The average reduction in 8-hour ozone at monitoring sites projected to be nonattainment in the 2014 base case is 0.3 parts per billion (ppb). The reductions in annual PM 2.5 , 24-hour PM 2.5 , and ozone
concentrations for individual
nonattainment and/or maintenance sites are provided in section IX.

Table III.A–4 compares projected EGU emissions with the Transport Rule to projected EGU emissions with CAIR.



### T ABLE 

### III.A–4—S IMPLE 

### C OMPARISON OF 

### SO 2 AND 

### NO X 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS IN 

### S TATES IN

THE 

### CAIR OR 

### T RANSPORT 

### R ULE 

### R EGIONS 

### * FOR 

### E ACH 

### R ULE

2005 2012 2014

Actual Transport rule CAIR ** Transport rule CAIR **

SO 2 (Million Tons) ................................................................ 9.5 4.1 5.1 3.3 4.6

NO X (Million Tons) .............. Annual ................................
Ozone Season ................... 2.9

1.0 1.6

0.7 1.7

0.8 1.6

0.7 1.7

0.8

* Emissions totals include states covered by either the Transport Rule or CAIR. For PM 2.5 (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 NO X totals are as originally projected for 2010. This CAIR modeling represents a scenario that differed somewhat from the final CAIR (the modeling did not include a r egionwide ozone season NO X cap and included PM 2.5 requirements for the state of Arkansas).


### 45218 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

In addition to discussion of EPA’s proposed 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 (sectionIX), economic impacts (section X), enduse energy efficiency (section XI), and statutory and executive order reviews (section XII).

Table III.A–5 shows the results of the cost and benefits analysis for the proposed and alternate remedies.
Further discussion of these results is contained in preamble section XII-A and in the Regulatory Impacts Analysis. A listing of health and welfare effects is provided in RIA Table 1–6. Estimates here are subject to uncertainties discussed further in the body of the
document. The social costs are the loss of household utility as measured in Hicksian equivalent variation. The capital costs spent for pollution controls
installed for CAIR were not included in
the annual social costs since the Transport Rule did not lead to their installation. Those CAIR-related capital investments are roughly estimated to
have an annual social cost less than $1.15 to $ 1.29 billion (under the two discount rates.)

Most of the estimated PM-related
benefits in this rule accrue to populations exposed to higher levels of

PM 2.5 . Of these estimated PM-related mortalities avoided, about 80 percent occur among populations initially exposed to annual mean PM 2.5 level of

10 μ g/m 3 and about 97 percent occur among those initially exposed to annual

mean PM 2.5 level of 7.5 μ g/m 3 . These are the lowest air quality levels considered
in the Laden et al. (2006) and Pope et al. (2002) studies, respectively. This fact is important, because as we estimate PM-related mortality among populations exposed to levels of PM 2.5 that are successively lower, our confidence in the results diminishes. However, our analysis shows that the great majority of the impacts occur at higher exposures.



### T ABLE 

### III.A–5—S UMMARY OF 

### A NNUAL 

### B ENEFITS 

### , C OSTS



### , AND 

### N ET 

### B ENEFITS OF 

### V ERSIONS OF THE 

### P ROPOSED 

### R EMEDY 

### O PTION IN 

### 2014 a

[Billions of 2006$]

Description Preferred remedy—State budgets/ limited trading Direct control Intrastate trading

Social costs: 3% discount rate .............................. $2.03 ..................................................... $2.68 .................. ................................... $2.49. 7% discount rate .............................. $2.23 ..................................................... $2.91 .................. ................................... $2.70.
Health-related benefits: b, c 3% discount rate .............................. $118 to $288 + B .................................. $117 to $286 + B .................................. $113 to $276 + B. 7% discount rate .............................. $108 to $260 + B .................................. $108 to $262 + B .................................. $104 to $252 + B. Net benefits (benefits-costs): 3% discount rate .............................. $116 to $286 ......................................... $115 to $283 ......................................... $110 to $273. 7% discount rate .............................. $105 to $258 ......................................... $105 to $259 ......................................... $101 to $249.

**Notes:** (a) All estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for the year 2014. For notational purposes, unquantified benefits are indicated with a ‘‘ B ’’ to represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits that we were able to quantify. (b) The reduction in premature mortalities account for over 90 percent of total monetized benefits. Benefit estimates are national. Valuation assumes discounting over the SAB-recommended 20-year segmented lag structure described in Chapter 5. Results reflect 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000; OMB, 2003). The estimate of social benefits also includes CO 2 -related benefits calculated using the social cost of carbon, discussed further in Chapter 5. Benefits are shown as a range from Pope et al. (2002) to Laden et al. (2006). Monetized benefits do not include unquantified benefits, such as other health effects, reduced sulfur deposition or visibility. These models assume that all fine particles, regardless of their chemical composition, areequally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle type. (c) Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all unquantified benefits and disbenefits. Potential benefit categories that have not been quantified and monetized are listed in RIA Table 1–4.

B. Background

1. What is the source of EPA’s authority
for this action?

The statutory authority for this action is provided by the 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 provisions— (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 this 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 interstate 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 state. 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 DC Circuit in Michigan v. EPA , 213 F.3d 663 (DC Cir. 2000). The CAIR, promulgated in 2005, was remanded by
the DC Circuit in North Carolina v. EPA

, 531 F.3d 896 (DC Cir. 2008), modified on reh’g , 550 F.3d. 1176 (DC 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 out [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,


### 45219 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

EPA is clarifying the applicability of section 110(a)(2)(D)(i)(I) by proposing to identify SO 2 and NO X emissions that each affected state must prohibit pursuant to that section with respect to
the PM 2.5 NAAQS promulgated in 1997 and 2006 and the 8-hour ozone NAAQS promulgated in 1997. The improvements in air quality that would result 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 maintenance 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.

Section 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 promulgate 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 revision submitted by the State does not satisfy the
minimum criteria 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 Administrator 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 greater detail in section 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 PM 2.5 NAAQS and/or the 2006 PM 2.5 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 submission that corrects the SIP 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, aggravation 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 certain 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 to which it is related, 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, PM 2.5 are 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
Web site at http://www.epagov/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 sensitive forests and farm crops; and affecting the diversity of ecosystems. More information about
these effects is available at EPA’s Web site 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

PM 2.5 as the indicator (62 FR 38652).
These revisions established an annual
standard of 15 μ g/m 3 and a 24-hour
standard of 65 μ g/m 3 . During 2006, EPA revised the air quality standards for

PM 2.5 . The 2006 standards decreased the level of the 24-hour fine particle
standard from 65 μ g/m 3 to 35 μ g/m 3

, and retained the annual fine particle
standard at 15 μ g/m 3

.

In the preamble to the final rule for CAIR in May 2005, EPA 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/m 3 annual PM 2.5 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

PM 2.5 standard.

The PM 2.5 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/m 3 annual PM 2.5 standard are located across a significant portion of the eastern 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 PM 2.5 standard.

The PM 2.5 ambient air quality monitoring for this same 2006–2008 time period shows that areas violating
the 2006 24-hour PM 2.5 standard of 35

μ g/m 3 ( i.e. , the revised 2006 standard
for 24-hour PM 2.5 ) 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 PM 2.5 standard.

EPA believes that a great deal of the improvement in PM 2.5 annual 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


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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
nonattainment 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 PM 2.5 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 that may result from the review by October 2011. EPA is planning to propose the revised standards by February 2011.

b. Ozone

Short-term (1- to 3-hour) and prolonged (6- to 8-hour) exposures to
ambient ozone have been linked to a
number of adverse health effects. 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 more 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 lung 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 shortterm 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 outdoors. This rule, and the NAAQS which it is related to, consider
the effects of ozone on 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 aesthetic 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, at the same time we revised
the PM 2.5 standards, EPA issued its final action to revise the NAAQS for ozone (62 FR 38856) to establish 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 fourth 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 (69 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 nonattainment areas to be re-designated to attainment. In addition, 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 NO X 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 reports discussing the
effect of the NO X SIP Call reductions
can be found on EPA’s Web site 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 standards began to
reduce mobile source emissions as the fleet began turning over vehicles to meet tightened NO X 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 soon. 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

. 3. Which NAAQS does this proposal
address?

This proposed action addresses the requirements of CAA section 110(a)(2)(D)(i)(I) as they relate to:

(1) The 1997 annual PM 2.5 standards, (2) The 2006 daily PM 2.5 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 PM 2.5 standards only. The 1997 8- hour ozone standard is 0.08 ppm. The

1997 PM 2.5 standards promulgated in
1997 established a 15 μ g/ 3 standard for
24-hour PM 2.5 and a 65 μ g/m 3 standard
for annual PM 2.5 . In 2006, the 24-hour

PM 2.5 standard was lowered to 35 μ g/m 3 and the 15 μ g/m 3 annual PM 2.5 standard was left unchanged.


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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. ’’ For this proposal, EPA fully addresses the requirements of CAA section 110(a)(2)(D)(i)(I) for the annual PM 2.5 standard of 15 μ g/m 3 . For the 24-hour
standard of 35 μ g/m 3 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 the 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 Transport Rulemaking History

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 (sections 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 as demonstrations of attainment of the ozone NAAQS by either 1982 or 1987 (section 172).

In addition, the 1977 Amendments included two provisions focused on interstate transport of air pollutants: the predecessor to current section 110(a)(2)(D), which requires 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 expeditious as 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
interference with maintenance. Significant contribution and
interference with maintenance are
discussed in detail in section IV later.

The 1990 Amendments reflect general awareness by Congress that ozone is a regional, and not merely a local, problem. Ozone and 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 controls, both Federal and State, across the country.

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 petition 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 controls 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 section 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
reduce NO X emissions throughout the region. 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 emissions rate limits from certain coal plants under Title IV.

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 difficult 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


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8 Guidance for Implementing the 1-hour Ozone and Pre-Existing PM10 NAAQS, Memorandum from Richard D. Wilson, dated December 29, 1997. 9 The 8 states were Connecticut, Massachusetts, Maine, New Hampshire, New York, Pennsylvania, Rhode Island, and Vermont. 10 See Michigan v. EPA, 213 F.3d 663 (DC Cir. 2000), cert. denied, 532 U.S. 904 (2001) (NO X SIP call) and Appalachian Power v. EPA, 251 F.3d 1026 (DC Cir. 2001) (technical amendments). modeling into their local plans, EPA extended the submittal date 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 EPA 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 promulgate 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 ozone 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 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 or 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 necessary 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. Therefore, 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 program 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 welfareeffects at levels allowed by the preexisting 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 standard 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 new primary standard. The new secondary standard provided increased protectionto the public welfare against ozoneinduced 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 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
each 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 Certain 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 other states, and the rule required
affected states to amend 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 states 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 Call rule, the Court issued two decisions concerning the NO X SIP
Call and its technical amendments. 10 The Court decisions, discussed later, generally upheld the NO X SIP Call 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 Call coincided with the litigation 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 Call based on the 8-hour NAAQS (65 FR 56245, September 18, 2000). Therefore, for the most part, the Court did not
address NO X SIP Call requirements under the 8-hour ozone NAAQS.

(1) What was the NO X SIP Call?

The NO X SIP Call was EPA’s principal effort to reduce interstate transport of precursors for both the 1-hour ozone 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 publicinput generated through notice-andcomment rulemaking. The EPA believed


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11 U.S.EPA. September, 2009. The NO X Budget Trading Program: 2008 Environmental Results, p.9. 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 both 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 areas to attain and maintain the ozone NAAQS.

This NO X SIP Call 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 measures 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 specified amounts of emissions reductions. By eliminating these
amounts of NO X emissions, the control
measures would assure that 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 large 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 contribute 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 NO X SIP Call.

(2) Legal Challenges to the NO X SIP Call

Several petitioners challenged the

NO X SIP Call in the United States Court of Appeals for the District of Columbia Circuit (DC Circuit). In Michigan v. EPA

, 213 F.3d 663 (DC Cir., 2000), cert. denied , 532 U.S. 904 (2001), the Court upheld the rule in most respects. Of greatest relevance here, the Court 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 airquality modeling and its use of costeffectiveness criteria 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 NO X emissions by an amount achievable with highly cost effective controls). See id. 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). See id. at 681–85, 692–94. The Court also subsequently delayed the implementation date to May 31, 2004. Michigan v. EPA, 2000 WL 1341477 (DC 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 id. 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 corrections to the NO X SIP Call, the DC 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 (DC Cir. 2001). More recently, the Court also rejected a challenge to a subsequent EPA rule withdrawing EPA’s findings of significant contribution for Georgia for
the 1-hour ozone standard. See North
Carolina v. EPA , 587 F.3d 422 (DC 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 the 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 affected 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 in 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 generally active from the start of the program in 2003. Prices and trading were down in 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 PM 2.5 , saving 580–1,800 lives annually 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 emissions reductions 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 NO X Budget Trading Program.

(4) Clean Air Interstate Rule

Following promulgation of the new NAAQS in 1997, the CAA required all states, 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 which are 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
interfere with maintenance in one or
more downwind states. Section 110(k)(5) authorizes EPA to find that a SIP is substantially inadequate to meet any CAA requirement. If EPA makes such a finding, it is to require the state


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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 PM 2.5 and their precursor emissions and/or transport of both ozone and its precursor emissions. 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 Call, 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 PM 2.5 nonattainment. However, EPA stated in the CAIR that it believed that, given current knowledge, it was not appropriate to specify emissions reductions requirements for direct PM 2.5 emissions or organic 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 is the CAIR?

The CAA contains a number of requirements to address nonattainment
of the PM 2.5 and the 8-hour ozone NAAQS, including requirements 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 amounts of transported

PM 2.5 , ozone, and their emissions precursors that significantly contributed
to nonattainment in downwind states.

In the CAIR, promulgated on May 12, 2005 (70 FR 25162), EPA required SIP
revisions in 28 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 NO X — important precursors of PM 2.5 (NO X and

SO 2 ) and ozone (NO X )—were prohibited. Achieving the emissions reductions identified, EPA concluded, would address the states’ requirements under section 110(a)(2)(D)(i)(I) of the CAA and would help PM 2.5 and ozone
nonattainment areas in the eastern half
of the United States attain the standards. Moreover, EPA concluded that such
attainment would 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 visibility 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 PM 2.5 . It required significant reductions in emissions of

SO 2 and NO X , 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 NO X 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 2 and NO X emissions from
EGUs that contribute to the PM 2.5 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 NO X 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 assigned 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 approachtaken in CAIR using three model multistate cap and trade programs for SO 2 and NO X that EPA developed and that states could choose to adopt to meet the required emissions reductions in a flexible 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 significantly contributing upwind
emissions were eliminated. 70 FR 25165–66, May 12, 2005. In addition,
states that shared an interstate nonattainment area were expected to work together in developing the nonattainment SIP for that area, reducing emissions 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 PM 2.5 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 FIPs to address interstate transport. On March 15, 2006 the EPA 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 required power plants in affected states to participate in one or more of three separate emissions cap and trade programs that cover: (1) Annual 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 emissions reductions while providing regulated sources with flexibility in choosing compliance strategies.

The FIPs also provided states with an option to submit abbreviated SIPs to meet CAIR. Under this option, states
could 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

NO X emissions because they contribute

to PM 2.5 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 established requirements for Delaware and New Jersey with respect to both ambient air quality 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 DC

Circuit. In North Carolina v. EPA, 531


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F.3d 896, modified on 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 remand 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 the air quality modeling portion of the significant contribution analysis for

PM 2.5 , EPA’s use of whole states as the unit of measurement, and the first-phase

NO X compliance deadline of 2009 See
id. 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 that 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 programs 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 EPA 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 id. at 908. Moreover, it emphasized that where the rule constitutes 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 id.

The Court further rejected the state budgets for SO 2 and NO X 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 id. 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 had 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 id. at 908–11, 911–13, and 926–28.

(7) How the Clean Air Interstate Rule
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 NO X in the eastern United States. As explained previously, although the DC Circuit remanded the rule to EPA, it did so without vacatur allowing the rule
to remain in effect while EPA addresses the remand. Thus, CAIR is continuing to help states address ozone and PM 2.5 nonattainment and improve visibility, reducing transported precursors of SO 2 and NO X , through 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 annual 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:// camddataandmaps.epa.gov/gdm/ ) and
an assessment of emissions reduction
data will be available at the end of each compliance 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
the rule. North Carolina v. EPA, 531 F.3d 896, modified on reh’g, 550 F.3d 1176 (DC Cir. 2008).

The action EPA is proposing would respond to the July and December 2008 opinions of the DC Circuit 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 and 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 NO X and ozone

season NO X are directly linked to the measurement 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 necessary 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 under the
remanded CAIR. If finalized as proposed, these FIPs would eliminate or, at a minimum, make measurable progress towards eliminating emissions
of SO 2 and NO X that significantly
contribute to or interfere with
maintenance of the 1997 and 2006 PM 2.5 NAAQS and the 1997 ozone NAAQS in
the eastern half of the United States.

b. Address Transport Requirements With Respect to the Existing PM 2.5 Standards

This proposed rule is designed to address the requirements of section 110(a)(2)(D)(i)(I) of the CAA as they


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relate to the 1997 and 2006 PM 2.5 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 1997 ozone and PM 2.5 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 CAIR inadequate to satisfy the requirements of 110(a)(2)(D)(i)(I), neither EPA’s FIP implementing the requirements of CAIR nor any states SIPs that relied on CAIR to satisfy the 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 obligation.

Revisions to the 1997 PM 2.5 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 PM 2.5 NAAQS, the SIPs under 110(a)(2) were due on September 21, 2009. On June 9, 2010, EPA issued a notice making findings that states had
not submitted SIPs under the 2006 PM 2.5 NAAQS by the September 2009 deadline. 75 FR 32673. 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 July 9, 2012. This proposal is designed to provide FIPs for the 2006
standards to ensure that the 110(a)(2)(D)(i)(I) obligation is fully
satisfied as it 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 Transport Requirements With Respect to the 1997 Ozone
Standards

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 respect 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 standards as soon as possible.

d. Provide for a Smooth Transition From Existing Programs

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 requirements. 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 portions of the new requirements that provide the greatest benefits.

2. Key Guiding Principles

a. Appropriately Identify 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
emissions 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. The 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. Generally 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, only 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 affected 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 impossible 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 analysis representing 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 to 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 sources of transported pollutants as a first step will produce a more reasonable, equitable, and optimal strategy than one beginning
with local controls. The local measures analyses 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


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local measures, it is likely to be necessary to reduce significant regional transport from upwind states. EPA
continues 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 NO X
.

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 NO X 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 going 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

PM 2.5 nonattainment and maintenance
areas do not increase their contribution to those areas. Further, this proposal
would maintain the ozone season
emissions reductions achieved since 2005 in 26 states, ensuring that states that significantly contribute to
downwind ozone nonattainment and
maintenance areas do not increase their
contribution to those areas. Tables 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 States

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 requirements 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 Power Supply

EPA recognizes that requirements for EGUs must be mindful 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 Incentives and Flexibility to the Regulated Community

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, provides 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 Rockies, 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 PM 2.5 and
ozone is a substantial and critical component for attaining the ozone and

PM 2.5 NAAQS in the eastern United States. The significant reductions in ambient air pollutant concentrations since CAIR, due largely to the large reductions in transported emissions, only serve to reinforce this point.

Second, in developing the CAIR, EPA found that interstate transport (particularly for anthropogenic emissions) made much smaller
contributions to exceedances of the

1997 PM 2.5 standards in the western United States. At the time, the only
exceedances of the 15 μ g/m 3 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 emissions transport makes a relatively small contribution to
exceedances in the western United
States under the 2006 PM 2.5 standards. For these designations, EPA identified
several locations in the western U.S.
with exceedances of the 24-hour PM 2.5 standards. These locations were in
California and a few other western states: Alaska, Washington, Oregon, Utah, and Arizona. Technical support information describing the nature of the 24-hour PM 2.5 problem at each of these
locations is available at: http:// www.epa.gov/pmdesignations/
2006standards/tech.htm. A review of this information suggests to EPA that the Western 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 description 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 , NO X , mercury, and other

air toxics. ’’ In furtherance of this priority goal, and 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 , NO X , 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 statutes, 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 that 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 investments 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 rules that will drive these compliance investments are: (1) This transport rule; (2) potential future rules that may be needed to address transport under future revised ozone or fine particle health standards; (3) the


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CAA Section 112(d) standards; (4)
revisions to the NSPS for coal and oilfired electric utility steam generating units; and (5) 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 the NSPS program. Furthermore, as set forth in the recently 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 GHGs. Finally, 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 follows.

Transport Rule. This proposed transport rule includes emissions reductions requirements for EGUs to address interstate transport under the 1997 ozone NAAQS, the 1997 PM 2.5 NAAQS, and the 2006 PM 2.5 NAAQS. After considering public comments on this proposal, EPA will endeavor to issue a final rule in spring 2011.

Rules to Address Transport under Revised Air Quality Health Standards. EPA currently is reconsidering its 2008 national ambient air quality standards for ozone, and is conducting a periodic review of the particulate matter NAAQS, including the fine particle standards. The Act requires EPA to ensure that primary standards are requisite to protect public health with an adequate margin of safety, and to set secondary standards requisite to protect public welfare. The Act requires EPA to review, and revise if appropriate, the primary and secondary NAAQS on a 5-year schedule to ensure that air quality standards reflect the latest
scientific information on health and welfare effects. When air quality standards are set or revised, the Act requires revision of SIPs to ensure that these standards to protect public health and welfare are met expeditiously and,
in the case of the health-based standards, within timetables in the Act.

If more protective NAAQS are promulgated, further emissions reductions would likely be needed in states where pollution levels exceed air quality standards, and in upwind states with emissions that significantly contribute to the air quality problems in another state. This may result in
additional emission reduction requirements for facilities in the power sector, as well as for other sectors. The
reconsideration of the March 2008 ozone air quality standards will be completed soon, and the review of particulate matter air quality standards by October 2011. SIP deadlines and
attainment deadlines would flow from
those dates.

EPA plans to make expeditious determinations of upwind state emissions reduction responsibilities for NAAQS for which interstate transport is an issue. This approach will lead to earlier emissions reductions to protect public health, as well as provide other
benefits. In the North Carolina decision,
the court made clear that downwind
state nonattainment deadlines are legally relevant to the timing of reductions under section 110(a)(2)(D). Thus, expeditious determinations of upwind state responsibilities under section 110(a)(2)(D) can promote upwind reductions in time to help
downwind states meet attainment deadlines, enable states and EPA to provide sources with earlier information
on their emission reduction responsibilities, and maximize sources
lead time to reduce emissions.

If a more protective ozone NAAQS is issued in August, EPA would plan to propose an interstate pollution transport rule for that NAAQS in 2011. We would expect work on that proposal to proceed in parallel with efforts to finalize this Transport Rule for the 1997 and 2006 NAAQS. A final rule to address interstate pollution transport for a reconsidered ozone NAAQS would be anticipated in 2012. In view of the implementation schedule for a reconsidered ozone NAAQS, compliance dates would be later than the compliance dates proposed for this Transport Rule, and would take into
account attainment dates for that NAAQS and other factors such, as
control cost and installation time. For any revised PM 2.5 NAAQS, EPA plans to conduct a similarly expeditious analysis of interstate transport to support a
determination as to whether or not
further emissions reductions from the power sector are required under section 110(a)(2)(D), in light of the emissions reductions required by other power
sector rules.

A revised SO 2 NAAQS was issued on June 2 creating a new 1-hour SO 2 NAAQS which, when implemented, will protect Americans from asthma and respiratory difficulties associated with short term exposures to SO 2 . Although EPA does not expect peak SO 2 levels to be a long-range transport issue, power plants are among the sources that can contribute to peak SO 2 levels and will likely be evaluated by states as they
consider control measures to attain the new standards. Anticipated emissions reductions from power plants and other

SO 2 sources under other Clean Air Act (CAA or Act) requirements ( e.g. , transport rules, and MACT standards) are expected to play a significant role in
attainment of the 1-hour SO 2 NAAQS.

Section 112(d) Standards for Utility

Units. In 2008, the DC Circuit Court vacated the CAMR and the 112(n) Revision Rule, which removed coal- and oil-fired electric utility steam 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 emissions limits for mercury and other
HAPs emitted from these sources. As required by section 112, EPA will issue a set of emissions standards. In part, the section 112(d) rule will require that all existing major sources achieve the
emission limits for HAPs which will 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 currently 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, cadmium, selenium, and arsenic); (4) dioxins/furans; and, (5) other organic hazardous air pollutants. EPA expects to receive the requested data, 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-case basis if such extension is necessary for the
installation of controls. The CAA requires new sources to comply on the
effective date of the final rule or at startup, whichever is later. If EPA were to provide 3 years for compliance with the section 112(d) standards,


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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 compliancestrategies that take full advantage of cocontrol 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 standards for new, modified, 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 NO X and SO 2 and optional output-based standards for particulate matter. EPA is currently re-evaluating the standards in Subpart Da to determine whether they reflect the degree of emission limitation achievable through the application of the best system of emission reduction,
which the Administrator determines has been adequately demonstrated. EPA also has a pending voluntary remand to
decide whether NSPS standards for this source category should include limits on GHG emissions. EPA is considering
the timetable for these actions and decisions in light of legal obligations and policy considerations, including the desirability of the industry knowing its regulatory obligations to inform
investment decisions.

Regional Haze/BART. States are required to develop SIPs that address regional haze in scenic areas such as national 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. The 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. Reducing 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 of emissions reductions for consumers of electricity and for the power industry, 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 energy 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 resources 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 through 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 demand response, and EPA and DOE are assisting state governments in this effort. Local governments as well, through building codes, zoning, andother actions, can and do promote enduse energy efficiency. The Federal Energy Regulatory Commission (FERC) regulates 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 reliability and economic planning.

All of these entities will need to work in concert to achieve a truly efficient, reliable, cost-effective electric power system. EPA 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. The Office of Solid Waste and Emergency Response is developing revised regulations for coal combustion residues, which are the combustion byproducts associated with the use of coal as a fuel. The Administrator signed the proposed rule on May 4, 2010. Over the next few years, EPA’s Office of Water plans to develop two rules affecting electric generating units; the precise timing of these rules is being determined. 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 implications to the power sector, and the Agency intends to coordinate these regulations with the upcoming air regulations. We intend to maximize 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 forwardlooking 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 sector 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

NO X 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—who can play a significant role in promoting or requiring investment in energy efficiency. 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.

IV. Defining ‘‘ Significant 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 PM 2.5 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 approach and results used for


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14 In the NO X SIP Call, because the same criteria applied, the discussion 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). 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 interpreted to refer to areas designated

nonattainment. ’’ (63 FR 57375, footnote 25)

16 Although EPA’s air quality modeling techniques examined all of the upwind state’s emissions of ozone precursors (including VOC and

NO X ), only the NO X emissions had meaningful interstate impacts. 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 budgets 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 emissions reduction results.
Section IV.G describes how the proposed approach is consistent with 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 Used in NO X SIP Call and
the CAIR

a. Significant Contribution

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 specified 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 collectively could remove using highly
cost-effective controls. EPA defined this quantity of emissions as the ‘‘ significant
contribution. ’’ The approach used in each rule is described in more detail,
later.

NO X 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 determined 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 should 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) 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.

, ‘‘ collective 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 impact 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 quality factor is the
extent of downwind nonattainmentproblems. EPA considered the thencurrent air quality of the area, the predicted future air quality (assuming implementation of required controls but not the transport requirements that were the subject of 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 inventory 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 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
contribution was not calculated until the next step. Because 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 contribution 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 determined that emissions
that both were from states that exceeded


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17 EPA did not address 24-hour PM 2.5 NAAQS in CAIR, only the annual PM 2.5 NAAQS. the air quality thresholds and could be eliminated through the application of highly cost-effective controls constituted a given state’s significant
contribution.

Choice of Highly Cost-Effective
Standard. EPA chose the standard of

‘‘ highly cost-effective ’’ in order to assure state flexibility in selecting control strategies to meet the 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 other 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 werecost-effective, if not highly costeffective—remained available to the

states.

Determination of Highly Cost-Effective

Amount. EPA determined the dollaramount considered to be highly costeffective by reference to the costeffectiveness of recently promulgated or proposed NO X controls. EPAdetermined that the average costeffectiveness 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 the ozone standard, for which 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 highly
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 considerations 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 downwind 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 already incurred
ozone control costs. ’’ 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 (63 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 that 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 total 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 each of the source categories for which EPA
determined that such controls were available (63 FR 57378).

Electric 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 each 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 emissions 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 PM 2.5 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 significantly 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 downwind nonattainment areas, and the cost factor of highly cost-effective
controls. See 70 FR 25174.

Air Quality Factor—PM 2.5 . EPA employed air quality modeling techniques to assess the impact of each upwind state’s entire inventory of anthropogenic SO 2 and NO X emissions
on downwind nonattainment and
maintenance for the annual PM 2.5 NAAQS. 17 EPA determined that upwind

NO X and SO 2 emissions contribute significantly to annual PM 2.5 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 threshold air quality impact of 0.2 μ g/m3 for PM 2.5 . 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 to further evaluation (70 FR 25174–75).

This level reflects the fact that PM 2.5 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 of

PM 2.5 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 NO X and
VOC emissions on downwind
nonattainment. The EPA determined


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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 state’s 2010 and 2015 emissions reductions are necessary to the extent required by the rule because a downwind receptor linked to that upwind state will either (i) remain in nonattainment and continue to experience significant contribution to nonattainment from the upwind state’s emissions; or (ii) attain the relevant NAAQS but later revert to nonattainment due, for example, to continued growth of the emissions inventory. ’’ 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 in 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
numerical 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 that would result from application of highly cost-effective controls. In the CAIR, EPA determined the level of costs that would be highly cost-effective on 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

NO X controls were available at the time. EPA determined as highly cost-effective
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 NO X 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

nonattainment. See 70 FR 25175.

b. Interference With 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 maintenance 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 the meaning given to the term

‘‘ significant contribution. ’’ That approach, which was found inconsistent with the requirements of 110(a)(2)(D)(i)(I), is described later. EPA’s proposed new approach to interpreting ‘‘ interfere with

maintenance ’’ is described in section IV.D, later.

NO X 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 proposes to apply much the same approach in analyzing the first component of the ‘‘ interfere-withmaintenance ’’ 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 from 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 samepositions with respect to the interfere-withmaintenance test as described in the notice of proposed rulemaking.

In addition, the NO X SIP Call preamble stated:

This [interfere-with-maintenance] requirement * * * does 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 term

‘‘ contribute significantly, ’’ that is, through the same weight-of-evidence 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 (the 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, based 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

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 PM 2.5 , while we lacked historical data to support the same variability analysis, we characterized attaining the annual standard by 0.5 μ g/

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
less could be considered to raise

maintenance concerns.

2. Judicial Opinions

a. Significant Contribution

In North Carolina v. EPA, 531 F.3d. 896 (DC Cir. 2008), the Court held that the approach EPA used in CAIR to measure each state’s significant contribution was insufficient. EPA, 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 significant contribution analysis made it impossible for EPA to show that the


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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 effective’ 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 recognized that aspects of EPA’s methodology for analyzing significant contribution had been upheld in Michigan v. EPA, 213 F.3d 663 (DC Cir. 2000), and it left those holdings undisturbed. Specifically, the Court acknowledged its prior
conclusion that ‘‘ significance may
include cost ’’ North Carolina, 531 F.3d 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 ’’

. 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
downwind 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 PM 2.5 contribution threshold, see id. at 914–15. With regard to EPA’s application of 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 PM 2.5 nonattainment areas.
See id. at 926–28.

b. Interference With Maintenance

In the CAIR case, the 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. See North Carolina, 531 F.3d at 910. The Court rejected the approach used in CAIR reasoning that it ‘‘ provides 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 maintenance 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 and the NO X 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
contribution that constitutes its

‘‘ significant contribution ’’ and

‘‘ interference with maintenance. ’’ To do so, EPA uses maximum cost thresholds, informed by air quality considerations. Specifically, for each precursor pollutant ( i.e. , SO 2 and NO X for PM 2.5 and NO X 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 from EGUs in each individual upwind state at the appropriate maximum cost 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 NO X 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 NO X , and ozone-season

NO X . 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 it has been identified in this proposal) until they reach the higher cost threshold. The lower cost threshold applies to a state if
the reduction in emissions at that
threshold eliminates nonattainment and maintenance problems at all ‘‘ linked ’’

sites.

EPA considers that the maintenanceconcept has two components: Year-toyear 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, EPA 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 emissions reductions associated with the implementation 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.

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 legal flaws, the CAIR rule cannot remain in place and must be replaced. If EPA’s base case analysis


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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.

Following 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 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 Title 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.

Step Two: Quantifying Each State’s Significant Contribution

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 associated air quality impacts of
reductions in ozone-season NO X . To do so with respect to the 1997 and 2006

PM 2.5 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 identifying 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 Carolina, 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 statespecific basis. EPA first develops statespecific costs curves showing what level
of emissions 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 nonattainment and maintenance sites. This approach allows EPA to identify specific cost breakpoints based on air quality considerations (such as the cost at which the air quality assessment analysis projects large
numbers of downwind sites
maintenance and nonattainment problems would be resolved) or cost criteria (such as being a cost where large
emissions 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 ozone NAAQS
and the 1997 and 2006 PM 2.5 NAAQS.

B. Overview of Approach To Identify Contributing Upwind States

This section describes EPA’s proposal to require reductions in upwind
emissions of SO 2 and NO X to address

PM 2.5 transport and to require reductions in upwind emissions of NO X to address ozone-related transport. In addition, this section provides an 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
sources’ emissions were found to not significantly contribute to
nonattainment of the PM 2.5 or 8-hour
ozone standards or interfere with maintenance of those standards, in
downwind states.

The EPA assessed individual upwind

states ’’ 2012 projected ambient impacts
on downwind nonattainment and maintenance receptors for a 37-state region in the eastern U.S., and
established threshold values for PM 2.5 and ozone to identify those states whose impact does not constitute a significant contribution to air quality violations in
the downwind states. EPA used these same threshold values in considering the potential for upwind state emissions
to interfere with maintenance of the

PM 2.5 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 PM 2.5 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 in section IV.C., and directly affects 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 discussion of emissions trends in Chapter 7 of TSD entitled ‘‘ Emission Inventories, ’’ included in the docket for this proposal.)

1. Background

a. For the CAIR, how did EPA determine which pollutants were necessary to control to address interstate transport
for PM 2.5 ?

Section II of the January 2004 CAIR proposal summarized key scientific and technical aspects of the occurrence, formation, and origins of PM 2.5 , as well as findings and observations relevant to formulating control approaches for reducing the contribution of transport to


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fine particle problems (69 FR 4575–87). Key concepts and provisional
conclusions drawn from this discussion
were summarized as follows in the preamble to the final CAIR:

(1) Fine particles (measured as PM 2.5 for the NAAQS) consist of a diverse mixture of substances that vary in size, chemical composition, and source. The

PM 2.5 includes both ‘‘ primary ’’ 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 as follows: 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 emitted materials. The major gaseous precursors of PM 2.5 include SO 2 , NO X , 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 associated with sulfates and nitrates are typically the largest components of transported

PM 2.5 , 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,

PM 2.5 . 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. ’’ In such conditions SO 2 reductions would be less effective in reducing PM 2.5 , 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 through NO X 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 greater 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, as summarized in the CAIR proposal, EPA concluded that it was both appropriate and necessary to focus on control of SO 2 and NO X emissions as the most effective approach to reducing the contribution of interstate transport to PM 2.5

.

For the CAIR, the EPA did not include
emissions controls that affect other components of PM 2.5 , noting that

‘‘ current information relating to sources and controls for other components identified in transported PM 2.5 (carbonaceous particles, ammonium, and crustal materials) does not, at this time, provide an adequate basis for regulating the regional transport of emissions responsible for these PM 2.5 components. ’’ (69 FR 4582). For all of these components, the lack of knowledge of and ability to quantify accurately the interstate transport of these components limited EPA’s ability to include these components in the

CAIR.

b. For the CAIR, how did EPA determine which pollutants were necessary to control to address interstate transport for ozone?

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 conditions through atmospheric
reactions of two main classes of precursor compound: VOCs and NO X (mainly NO and NO 2 ). The term ‘‘ VOC ’’ includes many classes of compounds that possess a wide range of chemical properties and atmospheric lifetimes, which help determine 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 Web sites ( e.g., http://www.gov/ttn/chief. ) The relative importance of NO X and VOC in ozone
formation and control varies with localand time-specific factors, including the
relative amounts of VOC and NO X present. In rural areas 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 increased 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-made and biogenic organics and can indirectly

increase NO X as well ( e.g. , increased electricity generation for air conditioning). Summertime conditionsalso bring increased episodes of largescale 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 reducing 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. , 1,000s 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 important component of high ozone concentrations during the
extended summer ozone season. A series of more recent progress reports discussing the effect of the NO X SIP Call
reductions can be found on EPA’s Web

site at: http://www.epa.gov/airmarkets/ progress/progress-reports.html

.

In the notice of proposed rulemaking for CAIR, EPA noted that we continue to rely on the assessment of ozone


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19 For the CAIR, 24-hour PM 2.5 was not at issue
because there were little or no exceedances of the then-existing 65 μ g/m 3 24-hour standards 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 Scale 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 conducted 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 Web site at: http:// www.epa.gov/ttn/ecas/regdata/RIAs/

452

_ R

_ 08

_ 003.pdf

. For addressing 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 transport 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 Particles

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 predicted change, due to the upwind state’s NO X and SO 2 emissions, in annual 19 PM 2.5 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

*** ’’ 42 U.S.C. 7410(a)(2)(D)(i)(I). 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 single nonattainment

area.

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 NO X emissions, rather than treating them separately. We believed this approach was consistent with the chemical interactions in the atmosphere
of SO 2 and NO X in forming PM 2.5 . The
contributions of SO 2 and NO X emissions are generally not additive, but rather are interrelated due to complex chemical

reactions.

In the CAIR proposal, EPA proposed to establish a state-level annual average

PM 2.5 contribution threshold from anthropogenic SO 2 and NO X emissions that was a small percentage of the annual air quality standard of 15.0 μ g/

m 3 . The EPA based this proposal 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 PM 2.5 transport shows that, in general, PM 2.5 nonattainment problems 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 of 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 PM 2.5 , we have found
collective contribution to be a pronounced feature of the PM 2.5 transport problem, in part because the
annual nature of the PM 2.5 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 direction—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 PM 2.5 transport contribution threshold was appropriate. For the final CAIR EPA decided to apply a threshold of 0.20 μ g/

m 3 , such that any model result 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 ozone nonattainment, EPA 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 included 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 area.

The EPA’s first step in evaluating 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
maximum 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 metrics reflect three key
contribution factors:

• 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


### 45237 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 regarding the nature of pollutant contributions are still appropriate. EPA proposes to continue
to focus the PM 2.5 transport requirements on SO 2 and NO X transport, and the ozone transport requirements on

NO X
.

EPA recognizes that, in some circumstances, the state’s NO X contribution to PM 2.5 in downwind states may be considerably smaller than
the state’s SO 2 contribution to PM 2.5 in downwind states. 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 could realistically be achieved, would result in a very small change in ambient

PM 2.5 levels. EPA considered 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 NO X requirements currently required for their contribution

to PM 2.5 , annual NO X emissions would increase, with 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 PM 2.5 , 24-hour PM 2.5 , 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 PM 2.5 transport shows that, in general, PM 2.5 nonattainment problems 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 of particular upwind states. For ozone, as we found in 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 PM 2.5 and ozone.

A second reason that low threshold values are warranted, as EPA discussed in the notices for the CAIR, is that there are adverse health impacts associated
with ambient PM 2.5 and ozone even at low levels. See relevant portions of the CAIR proposal notice (63 FR 4583–84) and the CAIR final rule notice (70 FR 25189–25192).

For annual PM 2.5 for the final CAIR, as noted previously, EPA decided to use a single-digit value, 0.2 μ g/m 3 , rather than the two-digit value in the proposed CAIR, 0.15 μ g/m 3 . 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 PM 2.5 require that:

Annual PM 2.5 standard design values shall
be rounded to the nearest 0.1 μ g/m 3 (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 μ g/m 3

, EPA deemed it preferable for the final
CAIR to select the threshold value at the

nearest 0.1 μ g/m 3 as well, and hence one percent of the 15 μ g/m 3 , rounded to
the nearest 0.1 μ g/m 3 became 0.2 μ g/m 3

.

For the 24-hour standard of 35 μ g/m 3

, 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 percent of the NAAQS. The rounding requirements for the 24-hour
standard are indicated in section 4.3 as
follows:

24-hour PM 2.5 standard design values shall
be rounded to the nearest 1 μ g/m 3 (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 μ g/m 3 , and rounding to the nearest whole μ g/m 3 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 PM 2.5 , 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 air quality thresholds with the monitoring reporting requirements, and to use 2-digit values representing one percent of the NAAQS, that is, 0.15 μ g/m 3 for the annual standard, and 0.35 μ g/m 3 for
the 24-hour standard. EPA believes
there are a number of considerations 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 NAAQS. For example, if EPA were to retain the CAIR approach for the annual standard, any future lowering of the PM 2.5 NAAQS to
below 15 μ g/m 3 would reduce the air quality threshold to 0.1 μ g/m 3 . This would occur because any value less
than 0.15 μ g/m 3 ( e.g. , 0.14 μ g/m 3 ) would
be rounded down to 0.1 μ g/m 3 . 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 thresholds 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 section 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 the approach for PM 2.5 , and because it provides for a consistent approach that takes into account, and is applicable to, any future ozone standards below 0.08 ppm.

EPA seeks comment on the pollutants and air quality thresholds used for identifying states to be included under the proposed rule. In particular, EPA requests comment on alternatives to the 1 percent threshold. In addition, EPA requests comment on whether EPA should use the same rounding


### 45238 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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. 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.

23 Pouliot, G., Pierce., T. ‘‘ A Tale of Two Models: A comparison of the Biogenic Emission Inventory System (BEIS) and Model of Emissions of Gases and convention that was used in the final
CAIR for the 15 μ g/m 3 annual PM 2.5 standard, or whether commenters agree with EPA’s approach that does not use this rounding convention. To identify the potential effect of alternative
thresholds for the annual PM 2.5 standard, see Table IV.C–13 (showing state specific contributions to areas with
annual PM 2.5 nonattainment and maintenance issues) and Table IV.C–16 (showing state specific contributions to
areas with 24-hour PM 2.5 nonattainment and maintenance issues).

C. Air Quality Modeling Approach and
Results

1. What air quality modeling platform
did EPA use?

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 PM 2.5 , 24-hour PM 2.5 , 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 NO X emissions from upwind states on downwind annual average and
24-hour PM 2.5 concentrations at monitoring sites projected to be
nonattainment or have maintenance problems in 2012 for the 1997 annual
and 2006 24-hour PM 2.5 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 health 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 to these models, the evaluation of the air quality model compared to measured concentrations, and the procedures for projecting ozone and PM 2.5 concentrations for future year scenarios. We also provide in this section the
interstate contributions for annual average and 24-hour PM 2.5 , 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 scenarios: 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 FIPs. The remedy proposed for inclusion in the
FIPs 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 emissions in upwind states to annual average and 24-hour

PM 2.5 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 the Comprehensive Air Quality Model with Extensions (CAMx) version 5 20 to simulate ozone and PM 2.5 concentrations for the 2005 base year and the 2012 and 2014 future year scenarios. In contrast, for the CAIR EPA used two air quality models, CAMx version 3.1 for modeling ozone and the Community Multiscale Air Quality Model (CMAQ) version 4.3 for modeling

PM 2.5 . 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. The use of one model for both pollutants, as we have done for this proposal, provides a more scientifically integrated ‘‘ one atmosphere ’’ approach versus using
different models for ozone and PM 2.5 . 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 km. 21 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 Columbia. 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 emissions from various
sources and areas to ozone and PM 2.5 component species in other downwind
locations. The CAMx model was chosen for use in this proposal 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

PM 2.5 with CAMx. This platform provides an update to the now more
historical data in the 2001-based platform used for CAIR that included 2001 emissions, 2001 meteorology for modeling PM 2.5 , and 1995 meteorology for modeling ozone. In the remainder of this section we provide an overview of (1) the emissions and meteorological 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

PM 2.5 and ozone, and (4) the predicted
interstate contributions to downwind
nonattainment and maintenance. We also identify which predicted interstate
contributions are at or above the air quality impact thresholds described previously 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 nonroad 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

PM 2.5 were split into their component species using other data sources, to provide the modeling species needed by CAMx. Elevated point sources were identified 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 version 3.14. 23 24 The same


### 45239 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 System Version 3 (BEIS3), ’’ 4th Annual Community Multiscale Analysis System Conference, Chapel Hill, NC, September 26–28, 2005.

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

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), NO X , VOC,

PM 2.5 , and particulate matter less than ten microns (PM 10 ). While these data were preliminary, they more closely
reflect the PM 2.5 emissions from the
final release of MOVES 2010. To account for the temperature dependence
of PM 2.5 , 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 Continuous 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 NO X 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. 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 to create state-specific profiles to allocate from annual to monthly values and from daily to hourly values. Only the 2005 data were used to create state-specific factors for allocation from month to day, which is intended to preserve an appropriate level of daily temporal variability needed for this type of modeling.

Other significant augmentations were
also made to the 2005 NEI and include the following. The nonpoint inventory was augmented with the oil and gas exploration inventory 25 which includes
emissions in several states within the eastern U.S. 12 km modeling domain
and additional states within the national 36 km modeling domain. The commercial marine category 3 (C3) vessel emissions were augmented with gridded 2005 emissions from the previous modeling efforts for the rule
called ‘‘ Control 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 werereplaced with average-year countybased inventories. Additionally, the inventories were processed to provide the hourly, gridded, model-species needed by CAMx.

Tables IV.C–1 and IV.C–2 provide
summaries of SO 2 and NO X emissions by state by sector for the 2005 base year
for those states within the eastern 12 km modeling domain. Emissions 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 for 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 prescribed burning mentioned previously.



### T ABLE 

### IV.C–1—2005 B ASE 

### C ASE 

### SO 2 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR

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 27,260 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 1,824 103 196,005


### 45240 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–1—2005 B ASE 

### C ASE 

### SO 2 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR 

### —Continued

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

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 25,261 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 22,020 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 Oklahoma ................................................. 110,081 40,482 7,542 5,015 2,699 469 166,288 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 South 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 5,385 385 305 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 ........................................ 10,019,774 1,953,745 1,117,009 596,847 123,547 19,345 13,380,267



### T ABLE 

### IV.C–2—2005 B ASE 

### C ASE 

### NO X 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR

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 2,654 241,499 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 .................................................... 111,017 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 76,062 378 366,285 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 Massachusetts ......................................... 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 Oklahoma ................................................. 86,204 73,465 94,574 55,424 117,240 1,709 .................... 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 Texas ....................................................... 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


### 45241 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–2—2005 B ASE 

### C ASE 

### NO X 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR 

### —Continued

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Wisconsin ................................................. 72,170 40,688 21,994 75,981 147,952 256 359,042

Grand total ........................................ 3,223,184 1,931,111 1,301,726 3,647,215 5,758,880 80,931 15,943,047

(2) Development of Future Year

Emissions

The future base case scenarios represent predicted emissions in the absence of any further controls beyond those federal 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 point and nonpoint stationary sources, any local control programs that may be necessary

for areas to attain the annual PM 2.5 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 provide
2012 and 2014 summaries of emissions data for 2012 and 2014 modeling for all
sectors for SO 2 and NO X for states included in the 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.



### T ABLE 

### IV.C–3—2012 B ASE 

### C ASE 

### SO 2 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR

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
District 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 2,010 676,193 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 48,460 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 Pennsylvania ............................................ 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 .................................................... 0 902 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



### T ABLE 

### IV.C–4—2012 B ASE 

### C ASE 

### NO X 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Alabama ................................................... 121,809 74,832 31,958 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


### 45242 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–4—2012 B ASE 

### C ASE 

### NO X 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR 

### —Continued

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

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 Florida ...................................................... 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 71 542,957 Indiana ..................................................... 203,107 73,651 30,125 83,760 114,396 88 505,127 Iowa .......................................................... 66,316 39,301 15,064 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 52,454 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 81 552,945 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 ........................................... 15,493 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 .................................................... 0 800 3,406 3,077 10,328 179 17,790 Virginia ..................................................... 36,036 60,101 53,496 79,717 111,583 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



### T ABLE 

### IV.C–5—2014 B ASE 

### C ASE 

### SO 2 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR

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 1,221 20 340,596 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 14,728 468 618 631 103,005 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 10,712 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


### 45243 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–5—2014 B ASE 

### C ASE 

### SO 2 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR 

### —Continued

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

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 .................................................... 0 903 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



### T ABLE 

### IV.C–6—2014 B ASE 

### C ASE 

### NO X 

### E MISSIONS 

### (T ONS 

### /Y EAR 

### ) FOR 

### E ASTERN 

### S TATES BY 

### S ECTOR

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 71 503,676 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 ....................................................... 2,535 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 71,161 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 69,157 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 .................................................... 0 803 3,397 2,771 8,563 179 15,713 Virginia ..................................................... 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 base case EGU emissions used for the air quality modeling runs that predicted ozone and

PM 2.5 were obtained from version 3.02 EISA of the IPM ( http://www.epa.gov/ airmarkt/progsregs/epa-ipm/
index.html ). The 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 Source 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 IPM
Documentation. 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


### 45244 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

26 Grell, G., J. Dudhia, and D. Stauffer, 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. 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. 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).

Development of Future-Year Emissions Inventories for Mobile Inventories

Mobile source inventories 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 locomotives, 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-based emissions were computed for CO, NO X , VOC,

PM 2.5 , and PM 10 . The same MOVESbased PM 2.5 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 were 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 emissions 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 2009 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 nonpoint 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.

The future year emissions for other
sectors are described next. For all sector projections, EPA seeks comment on growth and control approaches, particularly where 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, emissions 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 Administration 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 refueling 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 from animal operations were projected based 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 sectors, 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 Mesoscale 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-readyinputs for CMAQ using the MM5-toCAMx 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 predicted 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


### 45245 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

27 Baker K. and P. Dolwick. Meteorological Modeling Performance Evaluation for the Annual 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.

30 Yantosca, B., 2006. GEOS–CHEMv7–04–11 User’s Guide, Atmospheric Chemistry Modeling Group, Harvard University, Cambridge, MA, March

05, 2006.

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. 32 I nteragency M onitoring of PRO tected V isual

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 Clean Air Status and Trends Network (CASTNET) 2005 Annual Report. EPA Office of Air
and Radiation, Clean Air Markets Division. Washington, DC. December 2006. statistical comparisons 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 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 proposal 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 modeling. Pollutant
concentrations at the boundaries of the coarse scale modeling domain were
obtained from a three-dimensional global atmospheric chemistry model,
the GEOSChem 30 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 2.0degrees x 2.5 degrees (latitudelongitude). The predictions were used to provide one-way dynamic boundary

conditions at three-hour intervals and

an initial concentration field for the

coarse scale simulations.

d. Model Performance Evaluation for

Ozone and PM 2.5

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 paired

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 are similar to what

was observed with measured data. The normalized mean bias for 8-hour daily

maximum ozone concentrations was

¥ 2.9 percent and the normalized mean error was 13.2 percent for the months of May through September 2005, based on an aggregate of observed-predicted pairs within the 12 km modeling domain. The

two PM 2.5 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 East, the model predictions of 24-hour average sulfate were lower than the corresponding measured values by 7 percent at urban sites and by 9 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 particulate nitrate were lower than the corresponding measured values by 12 percent at urban sites and by 4 percent

at rural sites in the IMPROVE monitoring network. The model performance statistics by season for

ozone and PM 2.5 component species are provided in the AQMTSD. 2. How did EPA project future
nonattainment and maintenance for
annual PM 2.5 , 25-Hour PM 2.5 , and 8-
hour ozone?

In this section we describe the approach for projecting future
concentrations of ozone and PM 2.5 to identify locations that are expected to be
nonattainment or have a maintenance problem in 2012. The nonattainment
and maintenance locations are based on projections of future air quality at existing ozone and PM 2.5 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 this 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 on the relative (percent) change in model predictions for each location.

a. How did EPA process ambient ozone
and PM 2.5 data for the purpose of projecting future year concentrations?

In this analysis we use measurements
of ambient ozone and PM 2.5 data that come from monitoring networks consisting of more than one thousand
ozone monitors and one thousand PM 2.5 monitors located across the country. The monitors are sited according to the spatial and temporal nature of ozone
and PM 2.5 , 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 interpretations. 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 PM 2.5 ambient data were processed consistent with the formats associated with the NAAQS for PM 2.5

. The resulting estimates are used to


### 45246 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

34 U.S. EPA, 2007: Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, PM 2.5 , and Regional Haze; Office of Air Quality Planning and Standards, Research Triangle Park, NC.

35 CAIR was promulgated in 2005 before the 35 ug/m 3 PM 2.5 NAAQS was finalized in 2006. Since
there were no violations in the eastern United States (base or future year) of the 1997 65 ug/m3 NAAQS, it was not necessary to project 24 PM 2.5 values as part of the modeling for CAIR. 36 If there is only one complete design value, then the nonattainment and maintenance design values
are the same.

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 PM 2.5 NAAQS are different. Therefore, there are fewer complete sites for the annual NAAQS. indicate the level of air quality relative to the NAAQS. For PM 2.5 , we evaluated
concentrations of both the annual average PM 2.5 NAAQS and the 24-hour

PM 2.5 NAAQS. The annual PM 2.5 standard is met when the 3-year average
of the annual mean concentration is

15.0 μ g/m 3 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. The 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 98th percentile PM 2.5 concentration is

35 μ g/m 3 or less. The 3-year average mean 98th percentile concentration is computed at each site by averaging the 3 individual annual 98th percentile values at each site. The 3-year average 98th percentile concentration is referred to as the 24-hour average design value.

As described later, the approach for projecting future ozone and PM 2.5 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 2005–2007 design values are accessible at http:// www.epagov/airtrends/values.html.

The procedures for projecting annual average PM 2.5 and 8-hour ozone conform to the methodology in the final attainment demonstration modeling guidance 34 . In the CAIR analysis, EPA did not project 24-hour PM 2.5 design
values 35 . The analysis for this proposed rule, in contrast, uses the 24-hour PM 2.5 methodology outlined in the modeling guidance.

b. Projection of Future Annual and 24-

Hour PM 2.5 Nonattainment and

Maintenance

Annual PM 2.5 modeling was performed for the 2005 base year
emissions 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

PM 2.5 standards in 2012. We refer to
these areas as nonattainment sites and maintenance sites respectively.

In general, the projection methodology involves using the model
in a relative sense to estimate the change in PM 2.5 between 2005 and the
future 2012 base case as recommended in the modeling guidance. Rather than use the absolute model-predicted future year ozone and PM 2.5 concentrations, the base year and future year predictions are used to calculate a (relative) percent change in ozone and

PM 2.5 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 design value predictions, even if the absolute model concentrations are over-predicted or under-predicted.

Concentrations of PM 2.5 in 2012 were estimated by applying the 2005 to 2012 relative change in model-predicted

PM 2.5 species to the (2003–2007) PM 2.5 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 period PM 2.5 concentrations. For
each FRM PM 2.5 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 2nd and 4th years are weighted twice, and the 1st and 5th years are weighted once. We refer to this as the 5-year weighted 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, monitoring 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 PM 2.5 NAAQS, and 736 sites which met this criteria for the 24-hour NAAQS. 37

EPA followed the procedures recommended in the modeling guidance for projecting PM 2.5 by projecting
individual PM 2.5 component species and then summing these to calculate the
concentration of total PM 2.5 . The model predictions are used in a relative sense to estimate changes expected to occur in each of the major PM 2.5 species. The

PM 2.5 species are sulfate, nitrate, ammonium, particle bound water, elemental carbon, salt, other primary

PM 2.5 , and organic aerosol mass by difference. Organic aerosol mass by
difference is defined as the difference
between FRM PM 2.5 and the sum of the other components. The procedure for calculating future year PM 2.5 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 PM 2.5 Nonattainment and

Maintenance

The following is a brief summary of the future year annual PM 2.5 calculations. Additional details are provided in the modeling guidance, MATS documentation, and the AQMTSD.

We are using 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 PM 2.5 speciation is
needed for the location of each FRM monitoring site. Since co-located PM 2.5 speciation data are only available at about 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 Chemical Speciation Network


### 45247 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 The modeling guidance recommends calculating annual PM 2.5 RRFs using a 3 x 3 grid cell array (9 grid cells) for a model resolution of

12km.

40 All of the calculations and assumptions are consistent with the default MATS settings (as described in the MATS user’s guide and the photochemical modeling guidance). Additionally, we did not explicitly model salt and therefore the salt concentration was held constant from the base

to future. Blank mass was assumed to be a constant

mass of 0.5 μ g/m 3 in both the base and future year.

41 For example, a calculated annual average

concentration of 14.94753 * * * becomes 14.94 when digits beyond two places to the right are
truncated. (CSN) 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 the 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 PM 2.5 ( i.e.

, sulfate, nitrate, ammonium, elemental carbon, organic carbon mass, particle bound water, salt, and blank mass). This is done by multiplying the monitoredquarterly mean concentration of FRMderived total PM 2.5 by the monitored fractional composition of PM 2.5 species for each quarter averaged over 3 years 38 ( e.g. , 20 percent sulfate fraction multiplied by 15 μ g/m 3 PM 2.5 equals 3

μ g/m 3 sulfate).

Step 2: For each quarter, calculate the ratio of future year to base year model predictions for each of the componentspecies. The result is a set of speciesspecific relative response factors (RRF) ( e.g. , assume that the model-predicted 2005 base year sulfate for a particular
location is 10.0 μ g/m 3 and the 2012
future concentration is 8.0 μ g/m 3 , then RRF for sulfate is 0.8). The RRFs are
calculated based on the modeled concentrations averaged over the nine grid cells 39 centered at the location of
the monitor.

Step 3: For each quarter and each of the species, multiply the base year quarterly mean componentconcentration (Step 1) by the speciesspecific RRF obtained in Step 2. This results in an estimated future year quarterly mean concentration for each species ( e.g. , 3 μ g/m 3 sulfate multiplied by 0.8 equals a future sulfate
concentration of 2.4 μ g/m 3 ).

Step 4: The future year concentrations for the remaining species are then
calculated. 40 The future year
ammonium is calculated based on the calculated future year sulfate and nitrate concentrations, using a constant value for the degree of neutralization of sulfate (from the ambient data). The future year particle bound water concentration is calculated from an empirical formula. The inputs to the formula are the future year concentrations of sulfate, nitrate, and ammonium (from step 3).

Step 5: 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 PM 2.5

.

Step 6: 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 PM 2.5 concentrations were applied for each
FRM site. The calculated annual PM 2.5 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 PM 2.5 NAAQS. Any value that is greater than or equal to 15.05 μ g/m 3 is rounded to 15.1 μ g/m 3 and is considered to be violating the NAAQS. Thus, sites with future year annual

PM 2.5 design values of 15.05 μ g/m 3 or greater, based on the projection of 5-year weighted average concentrations, are predicted to be nonattainment sites. Sites with future year maximum design
values of 15.05

μ g/m 3 or greater are predicted to be
maintenance 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

PM 2.5 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 PM 2.5 NAAQS as part of this proposal.

Table IV.C–7 contains the 2003–2007 base case period average and maximum
annual PM 2.5 design values and the corresponding 2012 base case average and maximum design values for sites projected to be nonattainment of the
annual PM 2.5 NAAQS in 2012. Table
IV.C–8 contains this same information for projected 2012 maintenance sites.



### T ABLE 

### IV.C–7—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### A NNUAL 

### PM 2.5 

### D ESIGN 

### V ALUES 

### ( μ G 

### / M 3 

### ) AT 

### P ROJECTED 

### N ONATTAINMENT 

### 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


### 45248 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–7—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### A NNUAL 

### PM 2.5 

### D ESIGN 

### V ALUES 

### ( μ G 

### / M 3 

### ) AT 

### P ROJECTED 

### N ONATTAINMENT 

### S ITES 

### —Continued

Monitor ID State County Average design value
2003–2007 Maximum design value
2003–2007 Average design value
2012 Maximum design value
2012

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
390610043 .................... 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 .................... Pennsylvania ............... Allegheny .................... 20.31 20.75 18.90 19.31 420031301 .................... Pennsylvania ............... Allegheny .................... 16.26 16.57 15.13 15.42 420070014 .................... Pennsylvania ............... Beaver ......................... 16.38 16.45 15.23 15.30 420710007 .................... Pennsylvania ............... Lancaster .................... 16.55 17.46 15.19 16.01 421330008 .................... Pennsylvania ............... 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 15.34



### T ABLE 

### IV.C–8—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### A NNUAL 

### PM 2.5 

### D ESIGN 

### V ALUES 

### ( μ / M 3 

### ) AT 

### P ROJECTED 

### M AINTENANCE 

### -O NLY 

### 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 390350027 ............... 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 ............................... Montgomery .................. 15.54 15.92 15.01 15.37
391510017 ............... Ohio ............................... Stark .............................. 16.15 16.59 14.99 15.40 420110011 ............... Pennsylvania ................. 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 540291004 ............... 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 PM 2.5 Nonattainment and

Maintenance

The following is a brief summary of the procedures used for calculating future year 24-hour PM 2.5 design values. Additional details are provided in the modeling guidance, MATS documentation, and the AQMTSD.
Similar to the annual PM 2.5 calculations, we are using the 2003–2007 base period FRM data for projecting future year design values. The 24-hour PM 2.5 calculations are computationally similar to the annual average calculations. The main difference is that the base period 24-hour 98th percentile PM 2.5 concentrations are projected to the future year, instead of the annual average concentrations. Also, the PM 2.5 species fractions and relative response
factors are calculated from observed and modeled high concentration days, instead of quarterly average data.

Both the annual PM 2.5 and 24-hour

PM 2.5 calculations are performed on a calendar quarter basis. Since all years and quarters are averaged together in the
annual PM 2.5 calculations, the individual years can be averaged together early in the calculations. However, in the 24-hour PM 2.5 calculations, only the high quarter from each year is used in the final calculations. This represents the 98th 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. To calculate final future year design values, the high quarter for each year is identified and then a five year weighted average of the high quarters for each site was calculated to derive the future year design value.

The following are the steps followed for calculating the 2012 base case 24-
hour PM 2.5 design values:

Step 1: At each FRM monitoring site, we identify the maximum 24-hour PM 2.5 concentration in each quarter that is less


### 45249 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

42 High ambient data and model days were defined as the top 10 percent days in each quarter
based on 24-hour concentrations of PM 2.5

.

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 2005 modeling

year. 44 Since there is only 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 quarters.

45 All of the calculations and assumptions are consistent with the default MATS settings (as described in the MATS user’s guide and the photochemical modeling guidance). Additionally, we did not explicitly model salt and therefore the

salt concentration was held constant from the base

to future. Blank mass was assumed to be a constant mass of 0.5 ug/m 3 in both the base and future year. than or equal to the 98th percentile value over the entire year. 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 identified in step 6.

Step 2: In this step we calculate quarterly ambient concentrations on

‘‘ high ’’ 42 days for each of the major component species of PM 2.5 (sulfate, nitrate, ammonium, elemental carbon, organic carbon mass, particle bound water, salt, and blank mass). This calculation is performed by multiplying
the monitored concentrations of FRMderived total PM 2.5 mass on the 10 percent highest days from each quarter, by the monitored fractional composition
of PM 2.5 species on the 10 percent highest PM 2.5 days for each quarter, averaged over 3 years 43 ( e.g. , 20 percent sulfate fraction multiplied by 40 μ g/m 3
PM 2.5 equals 8 μ g/m 3 sulfate).

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 for the top 10 percent of days based on predicted
concentrations of 24-hour PM 2.5 . The result is a set of species-specific relative response factors (RRF) for the high PM 2.5 days in each quarter ( e.g. , assume that the 2005 predicted sulfate concentration on the 10 percent highest PM 2.5 days for a quarter for a particular location is 20

μ g/m 3 and the 2012 base case

concentration is 16 μ g/m 3 , 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 44 species-specific RRF obtained in step 3. This leads to an estimated future quarterly concentration for each component. ( e.g. , 21.0 μ g/m 3
nitrate × 0.75 = future nitrate of 15.75

μ g/m 3 ).

Step 5: The future year concentrations for the remaining species are then
calculated. 45 The future year
ammonium is calculated based on the calculated future year sulfate and nitrate concentrations, using a constant value for the degree of neutralization of sulfate (from the ambient data). The future year particle bound water concentration is calculated from an empirical formula. The inputs to the formula are the calculated future year concentrations of sulfate, nitrate, and ammonium (from step 4).

Step 6: We sum the species concentrations to obtain quarterly PM 2.5 values. This step is repeated for each quarter 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 7: The estimated 98th percentile values for each of the 5 years are averaged over 3 year intervals 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 8: The maximum future design value is calculated by following the previous steps for 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. This maximum value is used to identify the 24-hour

PM 2.5 maintenance receptors.

The preceding procedures for determining future year 24-hour PM 2.5 concentrations were applied for each
FRM site. The 24-hour PM 2.5 design
values are truncated after the first decimal place. This approach is
consistent with the truncation and rounding procedures for the 24-hour

PM 2.5 NAAQS. Any value that is greater than or equal to 35.5 μ g/m 3 is rounded

to 36 μ g/m 3 and is violating the NAAQS. Sites with future year 5 year weighted average design values of 35.5

μ g/m 3 or greater, based on the projection of 5-year weighted average concentrations, are predicted to be nonattainment. Sites with future year maximum design values of 35.5 μ g/m 3 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 for the 24-hour

PM 2.5 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 PM 2.5 NAAQS as part of this proposal.

Table IV.C–9 contains the 2003–2007 base period average and maximum 24-
hour PM 2.5 design values and the 2012 base case average and maximum design values for sites projected to be 2012
nonattainment of the 24-hour PM 2.5 NAAQS in 2012. Table IV.C–10 contains this same information for projected 2012
24-hour maintenance sites.



### T ABLE 

### IV.C–9—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### 24-H OUR 

### PM 2.5 

### D ESIGN 

### V ALUES 

### ( μ G 

### / M 3 

### ) AT 

### P ROJECTED 

### N ONATTAINMENT 

### 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 ...................... Connecticut ................. New Haven ................. 38.3 40.3 35.7 36.6

170310052 .................... Illinois .......................... Cook ............................ 40.2 41.4 38.5 39.7


### 45250 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–9—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### 24-H OUR 

### PM 2.5 

### D ESIGN 

### V ALUES 

### ( μ G 

### / M 3 

### ) AT 

### P ROJECTED 

### N ONATTAINMENT 

### S ITES 

### —Continued

Monitor ID State County Average design value
2003–2007 Maximum design value
2003–2007 Average design value
2012 Maximum design value
2012

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 .................... Illinois .......................... 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 34.6 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 .................... Michigan ...................... Oakland ....................... 39.9 40.4 37.9 38.4 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
360610056 .................... 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 ............................. Franklin ....................... 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
390617001 .................... 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


### 45251 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–9—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### 24-H OUR 

### PM 2.5 

### D ESIGN 

### V ALUES 

### ( μ G 

### / M 3 

### ) AT 

### P ROJECTED 

### N ONATTAINMENT 

### S ITES 

### —Continued

Monitor ID State County Average design value
2003–2007 Maximum design value
2003–2007 Average design value
2012 Maximum design value
2012

391530017 .................... Ohio ............................. Summit ........................ 38.0 39.6 35.6 37.2 420030008 .................... Pennsylvania ............... Allegheny .................... 39.4 39.9 35.9 36.3 420030064 .................... Pennsylvania ............... Allegheny .................... 64.2 68.2 58.8 62.3 420030093 .................... Pennsylvania ............... Allegheny .................... 45.6 51.5 41.1 46.2 420030116 .................... Pennsylvania ............... Allegheny .................... 42.5 42.5 37.1 37.1 420031008 .................... Pennsylvania ............... Allegheny .................... 41.3 42.8 38.0 39.3 420031301 .................... Pennsylvania ............... Allegheny .................... 40.3 42.4 36.6 38.6 420070014 .................... Pennsylvania ............... Beaver ......................... 43.4 44.6 37.7 39.1 420110011 .................... Pennsylvania ............... Berks ........................... 37.7 39.1 35.8 37.0 420210011 .................... Pennsylvania ............... Cambria ....................... 39.0 39.4 40.3 40.7 420430401 .................... Pennsylvania ............... Dauphin ....................... 38.0 39.0 35.7 37.1 420710007 .................... Pennsylvania ............... Lancaster .................... 40.8 44.0 37.7 40.1 421330008 .................... Pennsylvania ............... York ............................. 38.2 40.7 35.9 38.8 471251009 .................... Tennessee .................. Montgomery ................ 36.3 37.5 36.6 37.9

540090011 .................... West Virginia ............... Brooke ......................... 43.9 44.9 39.9 40.8

550790010 .................... Wisconsin .................... Milwaukee ................... 38.6 40.0 37.7 39.0

550790026 .................... Wisconsin .................... Milwaukee ................... 37.3 41.3 36.3 40.1

550790043 .................... Wisconsin .................... Milwaukee ................... 39.9 40.8 38.8 39.7

550790099 .................... Wisconsin .................... Milwaukee ................... 37.7 38.7 36.8 37.7



### T ABLE 

### IV.C–10—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### 24-H OUR 

### PM 2.5 

### D ESIGN 

### V ALUES 

### ( μ G 

### / M 3 

### )

AT 

### P ROJECTED 

### M AINTENANCE 

### -O NLY 

### S ITES

Monitor ID State County Average design value
2003–2007 Maximum design value
2003–2007 Average design value
2012 Maximum design value
2012

110010041 ............... Washington DC ............. Washington DC ............. 36.3 37.8 34.0 35.6 110010042 ............... Washington DC ............. Washington DC ............. 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 ............... Pennsylvania ................. Allegheny ....................... 38.7 40.7 34.3 36.6 420033007 ............... Pennsylvania ................. Allegheny ....................... 37.5 43.1 33.8 38.5 420410101 ............... Pennsylvania ................. Cumberland ................... 38.0 40.2 35.3 37.0 421255001 ............... Pennsylvania ................. 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 36.3

551330027 ............... Wisconsin ...................... Waukesha ..................... 35.4 36.2 34.9 35.6


### 45252 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 are 10 days. If there are less than 5 days > 70 ppb, then an RRF calculation is not completed

for that site. (3) Methodology for Projecting 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 base 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 across all days with 8-hour daily maximum 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-bysite 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 estimate 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 of 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 monitoring 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. Future year design values that are greater than or equal to 85 ppb are 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 year maintenance sites. Note that, as described previously for the annual and
24-hour PM 2.5 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 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 ozone 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 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 and the 2012 base case average and maximum design values for sites projected to be
2012 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.



### T ABLE 

### IV.C–11—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### 8-H OUR 

### O ZONE 

### D ESIGN 

### V ALUES 

### ( PPB 

### ) AT 

### P ROJECTED 

### N ONATTAINMENT 

### 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



### T ABLE 

### IV.C–12—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### 8-H OUR 

### O ZONE 

### D ESIGN 

### V ALUES 

### ( PPB 

### ) AT 

### P ROJECTED 

### M AINTENANCE 

### -O NLY 

### 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


### 45253 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

47 Zero-out modeling is a technique in which all emissions are removed ( e.g., NO X and 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. 

### T ABLE 

### IV.C–12—A VERAGE AND 

### M AXIMUM 

### 2003–2007 AND 

### 2012 B ASE 

### C ASE 

### 8-H OUR 

### O ZONE 

### D ESIGN 

### V ALUES 

### ( PPB 

### ) AT 

### P ROJECTED 

### M AINTENANCE 

### -O NLY 

### S ITES 

### —Continued

Monitor ID State County Average design value
2003–2007 Maximum design value 2003–
2007 Average design value
2012 Maximum design value
2012

90093002 ................... Connecticut ............... New Haven ................ 90 .3 93 82 .9 85 .4 130890002 ................. Georgia ...................... DeKalb ....................... 88 .7 93 81 .6 85 .6 131210055 ................. Georgia ...................... Fulton ........................ 91 .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 .6
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 assess interstate
contributions to nonattainment and

maintenance?

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 PM 2.5 , 24-hour PM 2.5 , and 8-hour 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 PM 2.5 and 8-hour ozone. Details of themodeling techniques and postprocessing procedures are described in
this section.

CAMx employs enhanced source apportionment techniques 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 PM 2.5 for individual receptor locations. The strength of the photochemical model source apportionment technique is that all
modeled ozone and/or PM 2.5 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 type of emissions apportionment is useful to understand the types of sources or regions that are contributing to ozone and PM 2.5 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 PM 2.5 , which is not possible with an emissions sensitivity approach such as zero-out, since the change in emissions leads to changes in pollutant concentrations, meaning the sum of
estimated ozone or PM 2.5 in all zero-out simulations may not exactly match the

ozone or PM 2.5 estimated in the base
model simulation. Photochemical model source apportionment has the additionaladvantage over emissions sensitivitybased approaches of being more computationally efficient. There is currently no technical evidence showing that one technique is clearly superior to the other for evaluating
contributions to ozone and PM 2.5 from various emission sources. However, since source apportionment explicitly tracks the formation and transport of all
ozone and PM 2.5 mass, it is particularly well suited for quantifying interstate contributions as part of this proposal. More details on the implementation 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 PM 2.5 , and both zero-out and source apportionment modeling for ozone. The CAIR modeling was
conducted at 36 km resolution for PM 2.5 and 12 km resolution for ozone. In contrast, the analysis for the Transport Rule was performed at 12 km resolution
for both ozone and PM 2.5 . When choosing the modeling techniques to use for the Transport Rule, we carefully considered 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 resource savings compared to zero-out modeling, we chose to perform the modeled contribution analyses for PM 2.5 and ozone with photochemical source apportionment.

The EPA performed source apportionment modeling for both ozone
and PM 2.5 for the 2012 base case emissions. In this modeling we tracked
the ozone and PM 2.5 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 maintenance receptors. The states EPA analyzed using source apportionment for ozone and for PM 2.5 are: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland, Massachusetts, 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, Washington DC, 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


### 45254 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

48 The water and ammonium contributions are calculated by MATS using the default assumptions that were used to calculate future year 2012 PM 2.5 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 neutralization 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. 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 the 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. or assess the contribution from
emissions in these states.

In contrast to CAIR, all contributions
to downwind nonattainment and maintenance receptors for the Transport Rule were calculated using a relative approach. This is similar to the approach used to calculate future year design values, 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, there are advantages of examining the relative contributions for
both ozone and PM 2.5 . 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
ozone and PM 2.5 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 PM 2.5 Contribution Modeling Approach

EPA used the CAMx Particulate Source Apportionment Technique (PSAT) to calculate downwind PM 2.5 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

PM 2.5 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

PM 2.5 emissions in each upwind state. Each state was a separate tag, and the tagged emissions followed state boundaries (not grid cells).

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 carbon, elemental carbon, and
other PM 2.5 ) 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

PM 2.5 , as described in section IV.C.4,
later.

We developed and applied several post-processing steps to transform the PSAT modeling outputs to PM 2.5 downwind contributions. The approach involved processing the PSAT model outputs 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 PSAT-predicted absolute contribution for each species ( e.g. ,sulfate) coupled with the CAMxpredicted 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 PM 2.5 design value. For calculating annual contributions, we included 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- hour calculations, only the upwind contribution to the highest quarter at each receptor was used ( i.e. , highest quarter based on 2012 PM 2.5 mass). For
both annual and 24-hour PM 2.5 , the total

PM 2.5 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 CAM X 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 VOCemissions. Through emissions preprocessing 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 downwind
ozone concentrations. There are several post-processing steps needed to transform the raw model outputs to
ozone downwind contributions. Wedeveloped and applied several postprocessing steps to transform the OSAT modeling outputs to ozone contributions at downwind receptors. The approach for ozone was similar to the approach for PM 2.5 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 contributionof ozone coupled with the CAMxpredicted 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 calculating the contribution metrics are provided in the AQMTSD.

c. Use of Projected Nonattainment and
Maintenance Contributions

The previous steps provide the details for calculating 8-hour ozone and annual
and 24-hour PM 2.5 contributions to alldownwind receptors. After the postprocessing 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 and PM 2.5 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


### 45255 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

contribution to a future year (2012) downwind nonattainment receptor. The
maximum contribution to maintenance is calculated based on the single largest contribution 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 means 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 are the estimated interstate
contributions to annual PM 2.5 , 24-Hour

PM 2.5 , and 8-Hour ozone nonattainment
and maintenance?

a. Contributions to Annual and 24-Hour

PM 2.5 Nonattainment and Maintenance

In this section, we present the
interstate contributions from emissions in upwind states to downwind
nonattainment and maintenance sites for the annual PM 2.5 NAAQS. We also present the interstate contributions from emissions in upwind states to
downwind nonattainment and
maintenance sites for the 24-hour PM 2.5 NAAQS. As described previously in section IV.B., states which contribute

0.15 μ g/m 3 or more to annual PM 2.5 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 PM 2.5 , states which contribute

0.35 μ g/m 3 or more to 24-hour PM 2.5 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 IV.C.3, we performed air quality modeling to quantify the contributions to annual and
24-hour PM 2.5 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, Massachusetts, 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 Wisconsin.

For annual PM 2.5 , we calculated each
state’s contribution to each of the 32 monitoring sites that are projected to be
nonattainment and each of the 16 sites that are projected to have maintenance problems for the annual PM 2.5 NAAQS in the 2012 base case. The largest
contribution from each state to annual

PM 2.5 nonattainment in downwind sites is provided in Table IV.C–13. The largest contribution from each state to
annual PM 2.5 maintenance in downwind sites is also provided in Table IV.C–13.
The contributions from each state to all projected 2012 nonattainment and
maintenance sites for the annual PM 2.5 NAAQS are provided in the AQMTSD.



### T ABLE 

### IV.C–13—L ARGEST 

### C ONTRIBUTION TO 

### D OWNWIND 

### A NNUAL 

### PM 2.5 

### ( μ G 

### / M 3 

### ) N ONATTAINMENT AND 

### M AINTENANCE

FOR 

### E ACH OF 

### 37 S TATES

Upwind state Largestdownwind contribution to nonattainment for annual
PM 2.5 ( μ g/m 3 ) Largestdownwind contribution to maintenance

for annual PM 2.5 ( μ g/m 3 )

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/Washington, D.C. ...................................................................................................... ............... 0.63 0.56
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 Carolina ................................................................................................................. ......................... 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 0.02
Tennessee ...................................................................................................................... ......................... 0.68 0.64
Texas .......................................................................................................................... ............................. 0.13 0.06
Vermont ........................................................................................................................ ........................... 0.00 0.00 Virginia ....................................................................................................................... .............................. 0.36 0.37


### 45256 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

50 EPA combined Maryland and the District of Columbia as a single entity in our contribution 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. 51 As noted above, we combined Maryland and the District of Columbia as a single entity in our contribution 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. 

### T ABLE 

### IV.C–13—L ARGEST 

### C ONTRIBUTION TO 

### D OWNWIND 

### A NNUAL 

### PM 2.5 

### ( μ G 

### / M 3 

### ) N ONATTAINMENT AND 

### M AINTENANCE

FOR 

### E ACH OF 

### 37 S TATES 

### —Continued

Upwind state Largestdownwind contribution to nonattainment for annual
PM 2.5 ( μ g/m 3 ) Largestdownwind contribution to maintenance

for annual PM 2.5 ( μ g/m 3 )

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 μ g/m 3 or more to downwind annual PM 2.5 nonattainment. These states are: Alabama, Delaware, the District of Columbia, 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 Wisconsin. In Table IV.C– 14, we provide a list of the downwind
nonattainment sites to which each upwind state contributes 0.15 μ g/m 3 or more (i.e., the upwind state to
downwind nonattainment ‘‘ linkages ’’ ).

There are 19 states and the District of
Columbia 51 which contribute 0.15 μ g/ m 3 or more to downwind annual PM 2.5 maintenance. These states are: Alabama, the District of Columbia, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Missouri, New Jersey, New York, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. In Table IV.C–15, we provide a list of

the downwind maintenance sites to which each upwind state contributes

0.15 μ g/m 3 or more (i.e., the upwind

state to downwind maintenance

‘‘ linkages ’’ ).


### 45257 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed RulesTABLEIV.C–14—UPWINDSTATE TODOWNWINDNONATTAINMENTSITE‘‘LINKAGES’’FORANNUALPM2.5Upwind StateNumber oflinkagesCounties containing downwind 24-hour PM2.5nonattainment sites (monitoring site ID)Alabama ....................................................................6 Bibb, GA(130210007)Clayton, GA(130630091)Fulton, 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)Georgia ......................................................................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(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)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(171630010)Jefferson, KY(211110043)Wayne, MI(261630015)Wayne, MI(261630033)Butler, OH(390170016)Cuyahoga, OH(390350038)Cuyahoga, OH(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(421330008)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)Clayton, 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)Michigan ....................................................................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(211110043)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)Minnesota ..................................................................1 Cook, IL(170310052)Missouri .....................................................................17 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(211110043)Butler, OH(390170016)Hamilton, OH(390610014)Hamilton, OH(390610042)Hamilton, OH(390610043)Hamilton, OH(390617001)Hamilton, OH(390618001)Cabell, WV(540110006)Kanawha, WV(540391005)New Jersey ...............................................................2 Lancaster, PA(420710007)York, PA(421330008)


### 45258 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed RulesTABLEIV.C–14—UPWINDSTATE TODOWNWINDNONATTAINMENTSITE‘‘LINKAGES’’FORANNUALPM2.5—ContinuedUpwind StateNumber oflinkagesCounties containing downwind 24-hour PM2.5nonattainment sites (monitoring site ID)New York ...................................................................8 Cuyahoga, OH(390350038)Cuyahoga, OH(390350045)Cuyahoga, OH(390350060)Allegheny, 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(10730023)Jefferson, AL(10732003)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, 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(540110006)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, 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(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)Tennessee .................................................................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(390610043)Hamilton, OH(390617001)Hamilton, OH(390618001)Allegheny, PA(420030064)Allegheny, PA(420031301)Beaver, PA(420070014)Cabell, WV(540110006)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(180970083)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(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)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)


### 45259 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed RulesTABLEIV.C–15—UPWINDSTATE TODOWNWINDMAINTENANCESITE‘‘LINKAGES’’FORANNUALPM2.5Upwind StateNumber oflinkagesCounties containing downwind 24-hour PM2.5nonattainment sites (monitoring site ID)Alabama ....................................................................1 Jefferson, KY(211110044)Georgia ......................................................................1 Jefferson, KY(211110044)Illinois ........................................................................13 Jefferson, KY(211110044)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)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(540030003)Brooke, WV(540090005)Hancock, WV(540291004)Marion, WV(540490006)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 Jersey ...............................................................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)Hancock, WV(540291004)Marion, WV(540490006)Ohio ...........................................................................9 Cook, IL(170313301)Cook, IL(170316005)Jefferson, KY(211110044)New York, NY(360610056)Berks, PA(420110011)Berkeley, WV(540030003)Brooke, WV(540090005)Hancock, WV(540291004)Marion, WV(540490006)Pennsylvania .............................................................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)Jefferson, 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)


### 45260 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed RulesTABLEIV.C–15—UPWINDSTATE TODOWNWINDMAINTENANCESITE‘‘LINKAGES’’FORANNUALPM2.5—ContinuedUpwind StateNumber oflinkagesCounties containing downwind 24-hour PM2.5nonattainment sites (monitoring site ID)Wisconsin ..................................................................2 Cook, IL(170313301)Cook, IL(170316005)


### 45261 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

52 As noted above, we combined Maryland and the District of Columbia as a single entity in our contribution 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. For 24-hour PM 2.5 , 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 PM 2.5 NAAQS in the 2012 base case. The largest
contribution from each state to 24-hour

PM 2.5 nonattainment in downwind sites is provided in Table IV.C–16. The largest contribution from each state to
24-hour PM 2.5 maintenance in downwind sites is also provided in
Table IV.C–16. The contributions from each state to all projected 2012
nonattainment and maintenance sites
for the 24-hour PM 2.5 NAAQS are provided in the AQMTSD.



### T ABLE 

### IV.C–16—L ARGEST 

### C ONTRIBUTION TO 

### D OWNWIND 

### 24-H OUR 

### PM 2.5 

### ( μ G 

### / M 3 

### ) N ONATTAINMENT AND 

### M AINTENANCE

FOR 

### E ACH OF 

### 37 S TATES

Upwind State Largest downwind contribution to nonattainment for 24-hour PM 2.5 ( μ g/m 3 ) Largest downwind contribution to maintenance for 24-

hour PM 2.5

( μ g/m 3 )

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 0.19 Maryland/Washington, DC ........................................................................................................ ............................... 2.63 1.82
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 .................................................................................................................. .......................................... 3.51 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 μ g/m 3 or more to downwind 24-hour PM 2.5 nonattainment. These states are: Alabama, 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 IV.C–17, we provide a list of the downwind
nonattainment counties to which each upwind state contributes 0.35 μ g/m 3 or more ( i.e. , the upwind state to
downwind nonattainment ‘‘ linkages ’’ ).

There are 23 states and the District of
Columbia which contribute 0.35 μ g/m 3 or more to downwind 24-hour PM 2.5 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 IV.C– 18, we provide a list of the downwind
maintenance sites to which each upwind state contributes 0.35 μ g/m 3 or more ( i.e. , the upwind state to
downwind maintenance ‘‘ linkages ’’ ).


### 45262 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–17—U PWIND 

### S TATE TO 

### D OWNWIND 

### N ONATTAINMENT 

### S ITE 

### ‘‘ L INKAGES 

### ’’ FOR 

### 24-H OUR 

### PM 2.5

Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 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 (340390004) 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 (390610006) 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 (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 (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) 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 (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 (261630033) 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 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) 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) Cook, 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 (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) 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)


### 45263 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

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) 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) 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 (420030093) Allegheny, PA (420030116) Allegheny, PA (420031008) Allegheny, PA (420031301) Beaver, PA (420070014) Berks, PA (420110011) Cambria, PA (420210011) York, 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 (295100007) St. Louis City, MO (295100087) New York, NY (360610128) Cuyahoga, OH (390350038) Cuyahoga, OH (390350045) Cuyahoga, OH (390350060) Cuyahoga, OH (390350065) Franklin, OH (390490024) Franklin, OH (390490025) Hamilton, OH (390610014) 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) 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 (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 (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) Monroe, MI (261150005) Oakland, MI (261250001) Washtenaw, MI (261610008) Wayne, MI (261630015) Wayne, MI (261630033) Wayne, MI (261630036) Butler, OH (390170003) Butler, OH (390170016) Butler, OH (390170017) Butler, OH (390171004) 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) 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 (550790010) 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 (420430401) 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 (261630019) 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)


### 45264 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

North Carolina ............ 11 Baltimore City, MD (245100040) Baltimore City, MD (245100049) Hudson, NJ (340171003) Hudson, NJ (340172002) 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 (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 (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 (245100049) 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 (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 (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) Lancaster, PA (420710007) 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) Madison, 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) Marion, 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 (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 (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 (540090011) 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) Tippecanoe, IN (181570008) 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 (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) 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 (420030116) 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 (340172002) Union, NJ (340390004)


### 45265 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

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) Jefferson, 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) 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 (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) 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) 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)



### T ABLE 

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### PM 2.5

Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

Connecticut ................ 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 (295100085) 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)

Indiana ........................ 34 District of Columbia (110010041) District 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 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) Cumberland, PA (420410101) Washington, PA (421255001) Sumner, TN (471650007) Brooke, WV (540090005) 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)


### 45266 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

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) Maryland ..................... 5 District of Columbia (110010041) 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 (170310050) 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 (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)

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 (211451004) 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 Muscatine, IA (191390015) Milwaukee, WI (550790059) 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 (110010041) 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 Baltimore 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, MI (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) 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)


### 45267 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

53 For two of the 16 projected maintenance sites (Harris Co., Texas sites 482011015 and 482011035) 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. 

### T ABLE 

### IV.C–18—U PWIND 

### S TATE TO 

### D OWNWIND 

### M AINTENANCE 

### S ITE 

### ‘‘ L INKAGES 

### ’’ FOR 

### 24-H OUR 

### PM 2.5 

### —Continued

Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

Milwaukee, WI (550790059) Waukesha, WI (551330027)

Tennessee .................. 21 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) Wayne, MI (261630001) St. Louis City, MO (295100085) Jefferson, OH (390810017) Lucas, OH (390950024) Lucas, 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 (110010042) 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 (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) 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) Cumberland, PA (420410101) Washington, PA (421255001) Sumner, TN (471650007) Dane, WI (550250047) 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)

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-hour 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, Massachusetts, 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 Wisconsin.

We calculated each state’s
contribution to each of the 11 monitoring sites that are projected to be

nonattainment 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 largest

contribution from each state to 8-hour

ozone nonattainment in downwind sites is provided in Table IV.C–19. The largest contribution from each state to 8-

hour ozone maintenance in downwind sites is also provided in Table IV.C–19.

The contributions from each state to all projected 2012 nonattainment and

maintenance sites for the 8-hour ozone NAAQS are provided in the AQMTSD.



### T ABLE 

### IV.C–19—L ARGEST 

### C ONTRIBUTION TO 

### D OWNWIND 

### 8-H OUR 

### O ZONE 

### N ONATTAINMENT AND 

### M AINTENANCE FOR 

### E ACH

OF 

### 37 S TATES

Upwind State Largest downwind contribution to nonattainment for

ozone (ppb) Largest 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


### 45268 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

54 As noted above, we combined Maryland and the District of Columbia as a single entity in our contribution 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

contributors to the same downwind nonattainment

counties. 

### T ABLE 

### IV.C–19—L ARGEST 

### C ONTRIBUTION TO 

### D OWNWIND 

### 8-H OUR 

### O ZONE 

### N ONATTAINMENT AND 

### M AINTENANCE FOR 

### E ACH

OF 

### 37 S TATES 

### —Continued

Upwind State Largest downwind contribution to nonattainment for

ozone (ppb) Largest downwind contribution to maintenance for

ozone (ppb)

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
Louisiana ...................................................................................................................... ............................................ 11.4 10.6
Maine .......................................................................................................................... ............................................. 0.0 0.0 Maryland/Washington, DC ........................................................................................................ ............................... 6.1 4.2
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 0.2

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, 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 ’’ ).



### T ABLE 

### IV.C–20—U PWIND 

### S TATE TO 

### D OWNWIND 

### N ONATTAINMENT 

### ‘‘ L INKAGES 

### ’’ FOR 

### 8-H OUR 

### O ZONE

Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 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) Brazoria, TX (480391004) Tarrant, TX (484391002)


### 45269 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–20—U PWIND 

### S TATE TO 

### D OWNWIND 

### N ONATTAINMENT 

### ‘‘ L INKAGES 

### ’’ FOR 

### 8-H OUR 

### O ZONE 

### —Continued

Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

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)

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) Philadelphia, 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, TX (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 Suffolk, 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 (480391004) Harris, TX (482010051) Harris, TX (482010055) Harris, TX (482010062) Harris, TX (482010066) 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)



### T ABLE 

### IV.C–21—U PWIND 

### S TATE TO 

### D OWNWIND 

### M AINTENANCE 

### ‘‘ L INKAGES 

### ’’ FOR 

### 8-H OUR 

### O ZONE

Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment 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) Harris, TX (482010029) 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 Dallas, TX (481130069) Kentucky ..................... 6 Fairfield, CT (90010017) Fairfield, CT (90011123) Fairfield, CT (90013007) New Haven, CT (90093002) Westchester, NY (361192004) Bucks, PA. (420170012).


### 45270 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.C–21—U PWIND 

### S TATE TO 

### D OWNWIND 

### M AINTENANCE 

### ‘‘ L INKAGES 

### ’’ FOR 

### 8-H OUR 

### O ZONE 

### —Continued

Upwind State Number of linkages

Counties containing downwind 24-hour PM 2.5 nonattainment sites (monitoring site ID)

Louisiana .................... 6 Dallas, TX (481130069) Dallas, TX (481130087) Harris, 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). Mississippi .................. 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) Fairfield, 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 Fairfield, 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) 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 (90011123) 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) Bucks, PA. (420170012).

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 contribution and interference with maintenance. EPA then applies that approach for the three different NAAQS being addressed in today’s notice: The 1997 ozone NAAQS, the
1997 annual PM 2.5 NAAQS and the 2006
24-hour PM 2.5 NAAQS.

With respect to the 1997 ozone NAAQS, 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 significant
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 PM 2.5 NAAQS, this proposal finds that 24 eastern states have SO 2 and NO X emission reduction responsibilities. We apply the proposed methodology to fully quantify the SO 2 and NO X emissions from each of these states that significantly contribute to or interfere
with maintenance in downwind areas.

With respect to the 24-hour PM 2.5 NAAQS, this proposal finds that 25
eastern states have emission 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’ significant
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 PM 2.5 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 PM 2.5 standard. If further analysis shows that other reductions should be considered as part of significant contribution or
interference with maintenance with respect to the 24-hour PM 2.5 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 section 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

PM 2.5 NAAQS and the ozone NAAQS. For this portion of the analysis, EPA expands upon the methodology used in
the NO X SIP Call and CAIR, but modifies it in significant respects. In the

NO X SIP Call and CAIR, EPA’s


### 45271 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 relying 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. Furthermore,
unlike the NO X 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 contribution to
nonattainment and interference with

maintenance.

The methodology takes into account
both the DC 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 at 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 regional 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 from EGUs in each state at 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 thedownwind state, at different cost-perton 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 costeffective. 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 quality and cost
considerations. This assessment is performed for each 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 NO X
. 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 remaining 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 methodology 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, there may be cases when upwind states contributing to a specific
downwind nonattainment area have already done a great deal to reduce
emissions while the downwind state 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 states (upwind or downwind) have large emissions (and a correspondingly large impact downwind) not because their sources are poorly controlled, but because they have a greater number of sources—the operation of which is critical to the reliability of the electric grid. Conversely, there may be cases where a state (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 better 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. Therefore, EPA believes that it is appropriate to consider both cost and air quality metrics when quantifying each state’s significant
contribution.

This methodology is consistent with the statutory mandate in section 110(a)(2)(D)(i)(I) which requires upwind states 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 this 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 the 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 adopt 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).


### 45272 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 receptor’s air quality problem has an unusually high local component. Given this structure, interpreting significant contribution and interfere with maintenance inherently involves a policy decision on how much emissions control responsibility should be assigned to upwind states, and how much responsibility should be left to downwind states. In virtually all areas,

PM 2.5 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 risks in the downwind state. Third, the influx of pollution from upwind states raises the pollution level in a downwind state, making it necessary for the downwind state to obtain deeper pollution reductions to attain and maintain air quality standards, which
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 interstate 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, the proposed methodology ensures that upwind states are not required to shoulder the entire responsibility for the downwind state’s
attainment and maintenance 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 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 significant contribution and
interference with maintenance. The required reductions would provide very substantial air quality improvements.
For the annual PM 2.5 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 concentration 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 Cost

Curves

The first step in EPA’s methodology for determining the quantity of emissions that represents each state’s significant contribution 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
reductions for EGUs in a state. In other words, EPA determined for specific cost per ton thresholds, the emissions
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 (dollars 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 state 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 detail on the development of the

cost curves, see the TSD, ‘‘ 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 assessment 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 available reductions. EPA therefore initially created cost curves based solely
on reductions from EGUs and determined appropriate cost thresholdsbased on that analysis. EPA then reexamined non-EGUs to determine the accuracy of its initial assumptions that
there 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
emissions 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 nonEGU 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.

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 PM 2.5 NAAQS must be eliminated by 2014, or as expeditiously as practicable. The cost curves show, among other things, that the amount of
emissions reductions that can be achieved for a given cost varies over


### 45273 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 looks at the remedy, including reductions in upwind states 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. time. This is true because, among other things, control 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, March2005), so if this rule is finalized in mid2011, emissions reductions from scrubbers by 2012 or 2013 can only 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 selective catalytic reduction (SCR) unit to reduce emissions of NO X
. (Boilermaker Labor Analysis and Installation Timing, USEPA, March 2005).

There are approximately 30 months between mid-2011 (when the Agency anticipates finalizing this rule) and January 2014 (the proposed Phase 2 compliance deadline). EPA believes this
is sufficient time for sources to install
the advanced emissions controls projected to be retrofit. EPA expects
about 14 GW of FGD and less than 1 GW of SCR capacity to be retrofit for Phase 2 of this rule. This is significantly less than the capacity that was retrofit in the same length of time after CAIR was finalized. EPA is not aware of problems or issues with sources meeting the CAIR compliance deadlines, either in equipment deliveries or labor availability. EPA believes the proposed Transport Rule compliance deadlines are reasonable, and will result in emissions reductions as quickly as practicable, delivering health benefits to the public and aiding states with NAAQS attainment deadlines.

EPA requests comment on the
schedule for scrubber and SCR installations, the availability of boilermaker labor, and any comment onwhether there might be alternative postcombustion cost-effective technologies
that could reduce SO 2 and/or NO X emissions. We also solicit comment on whether advanced coal preparation processes might provide emissions reductions at the significant
contribution cost levels identified in this proposal, whether such processes have been commercialized, and what the costs will be. In addition, EPA seeks comment on, whether other factors, such as other EPA regulatory actions,
will create an increase in boilermaker demand earlier than today’s proposal, in 2010 and beyond. We solicit comments on whether other factors might increase demand for boilermakers or control equipment, and what these factors would be. Comments in support of or opposed to the proposed compliance
deadlines should include information to support the commenter’s position.

Unlike add-on pollution controls such as scrubbers and SCRs, EPA believes
that low-NO X burners could be installed by 2012. See TSD, ‘‘ Installation Timing
for Low NO X Burners, ’’ in the docket for
this rule.

EPA also believes that sources can switch coals by 2012. Eastern bituminous coals used for power generation typically have more than
sufficient sulfur content to facilitate highly efficient collection of fly ash in a cold-side electrostatic precipitator (ESP). Some ESPs that operate at acceptably high collection efficiency when using a high-or medium-sulfur bituminous coal may experience some loss in collection efficiency when a
lower sulfur coal is used. Whether this occurs on a specific unit, and the extent to which it occurs, would depend on the design margins built into the existing ESP, the percentage change in coal sulfur content, and other factors. Relatively inexpensive practices to maintain high ESP performance on
lower sulfur bituminous coals are available and are being used successfully where necessary. These include a range of upgrades to ESP components and flue gas conditioning.

EPA assumes in the Transport Rule analysis that it will not be necessary for units that switch from higher to lower sulfur bituminous to make a costly replacement of the ESP. EPA’s analysis therefore does not add capital or operations and maintenance costs for coal switching from higher to lower
sulfur bituminous coals.

EPA’s analysis does not allow a unit designed for bituminous to switch to (very low sulfur) subbituminous coal
unless the unit has demonstrated that capability in the past. EPA assumes units with that capability have already made any investments needed to handle
a switch to subbituminous coals. EPA therefore assumes that any modeled coal switching from bituminous to
subbituminous has no cost or schedule impact.

EPA requests comment on the reasonableness of EPA’s assumption that coal switching within the bituminous coal grades will have relatively little cost or schedule impact

on most units.

b. Step 2. Performing the Air Quality

Assessment

In the second step, EPA uses an air quality assessment tool to estimate the impact of the upwind emissions
reductions 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 models used for attainment demonstrations, EPA believes this air quality assessment tool is acceptable for assessing the impact of numerous options on upwind reductions in the process of identifying upwind state significant contribution. It allows the Agency to analyze manymore potential scenarios than the timeand resource-intensive more refined air quality modeling would permit. This tool assesses the impact that reductions at a given cost breakpoint from all of the contributing states (as well as the state 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 contribution for ozone and

PM 2.5 can be found in the TSD,

‘‘ Analysis to Quantify Significant Contribution, ’’ in the docket for this
rule.

c. Step 3. Identifying Appropriate
Cost 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 multifactor assessment to identify which cost


### 45274 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

57 The cost thresholds 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 application under the Act. threshold 57 or thresholds should be used to quantify states’ significant
contribution and interference with maintenance. This new 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 threshold 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, allowing EPA to give greater weight to air quality considerations and making 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 quality data to identify breakpoints on
the 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 one or more of the potential breakpoints represent a
reasonable cost at which to define significant contribution for some or allupwind states. The factors in this multifactor assessment can be divided into two broad categories: Those that focus on air quality 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 still 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 the 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 considerations, emissions reductions requirements could be more costly than indicated in the modeling
because sources could choose one shortterm 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 contribute 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 and State rules ( i.e.

, similar to the highly cost effective concept in the NO X 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 quality and cost factors. One reason is that achieving attainment and maintenance of the air quality standard may require controls in upwind and downwind states that are more costly than previous controls (particularly if it is a new standard).

Based on this 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 appropriate 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 multiple 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 step of this analysis, EPA

uses the cost thresholds identified in theprevious step to determine, on a stateby-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 budgets and variability limits, which are in turn used to implement the requirements to eliminate significant contribution and

interference with maintenance. See
sections IV.E and IV.F.

2. Application

The discussion that follows explains how the methodology described previously was applied to quantify significant contribution with respect to

the 1997 and 2006 PM 2.5 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

PM 2.5 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 assessment 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 PM 2.5 , 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 interference with maintenance; whether there are ways to use our air quality 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.


### 45275 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

a. Specific Application to PM 2.5 (1) Year for Quantifying Significant
Contribution

EPA’s significant contribution analysis for PM 2.5 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 PM 2.5 standards. Furthermore, EPA believes that 2014 provides sources sufficient
lead time to 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 establish 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 by
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 Reductions Cost

Curves

This subsection provides more detail on the cost curves that EPA developed to assess the costs of reducing SO 2 and

NO X to address transport related to

PM 2.5 . It summarizes the information from the curves and then provides EPA’s interpretation 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 resulting state-specific emissions budgets.

To measure significant contribution
and interference with maintenance with respect to the PM 2.5 NAAQS, EPA developed cost curves showing the
annual NO X and annual SO 2 reductions
available in 2014 at different cost increments. 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 NO X , $5,000/ton for

ozone season NO X , and $2,400/ton for

SO 2 . For example, this means that EPA
examined reductions of annual NO X that are available at a cost of $2,500 per
ton or less. For SO 2 , the projected cost considered for reducing a ton of emissions 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.



### T ABLE 

### IV.D–1—2014 A NNUAL 

### NO X 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS FOR 

### E ACH 

### S TATE IN THE 

### T RANSPORT 

### R EGION AT 

### V ARIOUS 

### C OSTS
[(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 ................................................................................................................. 1 3 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
Tennessee ...................................................................................................................... . 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 better

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 approximately $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


### 45276 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 during the ozone season.

The cost curves demonstrate that many 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 NO X (large emissions reductions at relatively low
costs and additional reductions at relatively high costs) but the effect was not as pronounced. In 2014, 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 current equipment and continued use of low sulfur coal) are available at below $500/ton.

Table IV.D–2 shows that in 2014 there
are increased SO 2 emission reduction opportunities beyond just operating existing scrubbers and switching to low
sulfur coal. Installation of new scrubbers becomes feasible by 2014, thus increasing reduction opportunities at costs between $500/ton and $2,000/ ton (and above).



### T ABLE 

### IV.D–2—2014 SO 2 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS FOR 

### E ACH 

### S TATE IN THE 

### T RANSPORT 

### R EGION

AT 

### V ARIOUS 

### C OSTS
[(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 Kentucky ...................................... 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 ................................ 975 825 441 337 202 175 154 145 125
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 1,912

(3) Step 2. Air Quality Assessment of

Potential 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 states, 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 state

was ‘‘ linked ’’ to a different receptor), beyond those assumed in the base case.

The percent emissions reductions (and percent air quality improvement)


### 45277 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

that could be made by each upwind state in 2014 at different cost per ton levels are shown in Figures 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 that
emissions are not reduced from the
levels that exist at the 2014 zero dollar per ton (base case) cost level. It is
assumed that reductions in SO 2 emissions are linearly and directly proportional to downwind sulfate contributions. In other words, it is assumed that a specific 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 downwind 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.

Figures IV.D–1 through IV.D–4 show that at increased costs, there are
substantial increased emissions reductions. As explained previously,
each decrease in emissions is assumed to lead to a corresponding improvement in downwind air quality. These changes apply to both the daily and annual PM 2.5 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).


### 45278 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules


### 45279 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules


### 45280 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

58 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 PM 2.5

.

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-factor assessment in step 3 analyzed the results from the downwind receptor analysis in step 2 for the annual and daily PM 2.5 standards. Tables IV.D–3 and IV.D–4 show the air quality improvements in
2014 from the emissions reductions projected to occur at various costs. Table IV.D–4 also shows the average decrease in ambient daily PM 2.5 for

different sets of downwind sites for

various reductions in SO 2

.



### T ABLE 

### IV.D–3—E STIMATED 

### N UMBER OF 

### N ONATTAINMENT AND 

### / OR 

### M AINTENANCE 

### M ONITOR 

### S ITES IN 

### 2014 FOR 

### A NNUAL 

### PM 2.5 [As a function of SO 2 cost-per-ton levels]

Marginal cost per ton 2014 2014

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 >$500 .......................................................................................................................... ............................................. 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



### T ABLE 

### IV.D–4—D AILY 

### A IR 

### Q UALITY 

### I MPACTS VS 

### . SO 2 

### C OST PER 

### T ON 

### L EVELS IN 

### 2014

Marginal SO 2 cost per ton Number of remainingnonattainment andmaintenance monitor sites Air quality improvement (average μ g/

m ∧ 3 Reduction) relative to 2014 base case (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.

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. 58 As explained previously, this is because there are significant reductions available from sources that operate existing 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 NO X reductions in 2013 and 2014). The analysis also shows that higher cost reductions continue to provide downwind air quality improvements.


### 45281 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

59 When considering all reductions 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. (4) Identifying Cost Thresholds

(a) Considerations for 2014

For PM 2.5 , 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 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 starting 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 worsen 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 that
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, page 15), 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 nonattainment and maintenance concerns would be fully addressed in all areas, except for Allegheny County, Pennsylvania, when considering reductions from only states that contribute more than 1 percent. 59 As is explained later in this section, EPA believes that the monitor in Allegheny County that remains in nonattainment is in an area where the air quality problem is primarily local. Since EPA’s analysis suggests that the only remaining nonattainment 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 NO X reductions at reducing PM 2.5

. 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); there 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; and costs of up to $2,000/
ton of SO 2 are reasonable in comparison to other 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 is 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 level 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 PM 2.5 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 contribute to these three problem 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 significant 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 required 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 considered 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 sources, the Liberty-Clairton 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/
tsd

_ 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 PM 2.5 problem is more local in nature 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 Could Be Achieved by 2012

After determining that the amount of
emissions that could 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 follow, 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 require the installation of post-combustion SO 2 controls (scrubbers) or post-combustion

NO X 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 NO X burners are possible by 2012. For this reason, EPA believes it is appropriate to require these emissions to be removed in 2012,


### 45282 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

consistent with the Act’s requirement 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 States That Eliminate Their Significant Contribution for Less 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 or below $2,000/ton. EPA used the air quality assessment tool to analyze the impact of requiring all states linked to the downwind state site with an air quality problem, as well as the downwind state,
to reduce emissions consistent with the
levels discussed for 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 group 1 and group 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 group 2 and group 1 states because a significantly lower cost per ton was sufficient to resolve air quality problems at all downwind receptors linked to the group 2 states. Although states are linked to different sets of downwind receptors, our analysis indicated that the cost per ton needed to resolve downwind air quality problems varied only to a limited extent among states within group 1 and among states within group 2. The cost per ton did vary greatly between the group 1 and group 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 approach, support the decision to use uniform costs for a group of states.

(d) Proposed Cost Thresholds for PM 2.5

Summary of methodology. In summary, EPA determined that SO 2 emissions that could be reduced for $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 sites 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 states linked to
downwind PM 2.5 nonattainment and maintenance problems should be required to achieve those emissions reductions that can be reasonably achieved by 2012. Finally, EPA
determined that all states linked to
downwind PM 2.5 nonattainment ( see Table IV.D–5) and maintenance problems should, by 2012, remove all

NO X emissions that can be reduced for $500/ton in 2012.



### T ABLE 

### IV.D–5—S TATES 

### C OVERED FOR 

### SO 2 

### G ROUP 

### 1, SO 2 

### G ROUP 

### 2, AND 

### NO X 

### A NNUAL

States covered SO 2 group 1 SO 2 group 2 NO X annual

Alabama ........................................................................................................................ ............... ........................ X 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 ........................ X

Kansas ......................................................................................................................... ................ ........................ X X Kentucky ....................................................................................................................... ............... X ........................ X

Louisiana ...................................................................................................................... ................ ........................ X X Maryland ....................................................................................................................... ............... ........................ X X

Massachusetts .................................................................................................................. ........... ........................ X X Michigan ....................................................................................................................... ................ X ........................ X

Minnesota ...................................................................................................................... .............. ........................ X X

Missouri ....................................................................................................................... ................. X ........................ X

Nebraska ....................................................................................................................... ............... ........................ X X New Jersey ..................................................................................................................... ............. ........................ X X

New York ....................................................................................................................... .............. X ........................ X
North Carolina ................................................................................................................. ............. X ........................ X
Ohio ........................................................................................................................... .................. X ........................ X Pennsylvania ................................................................................................................... ............. X ........................ X
South Carolina ................................................................................................................. ............ ........................ X X

Tennessee ...................................................................................................................... ............. X ........................ X Virginia ....................................................................................................................... .................. X ........................ X West Virginia .................................................................................................................. .............. X ........................ X

Wisconsin ...................................................................................................................... ............... X ........................ X

Totals ......................................................................................................................... ........... 15 13 28


### 45283 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

After completing 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 PM 2.5 standards. While it would be possible for EPA to add additional 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 implications of these limitations and on possible options for addressing these limitations without unduly delaying necessary action.

(f) Use of Air Quality Assessment Tool; Results of More Detailed Air Quality Modeling Used To Evaluate the Tool

As discussed previously, EPA uses a simplified air quality assessment tool, 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 quality assessment tool, but raised
several issues on which EPA is requesting comment.

For the annual PM 2.5 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 PM 2.5 reductions in downwind states and projects that Allegheny County, PA would remain in nonattainment and that Birmingham,
AL would exceed the threshold for

‘‘ maintenance ’’ by a slight amount (less than 0.1 ug/m 3 ). Given the unique local nature of the Allegheny County, PA receptor ( see discussion previously),
EPA does not believe that 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 significant contribution to
nonattainment and interference with
maintenance with the annual PM 2.5 standard. Similarly, because the refined air quality modeling projects that Birmingham, AL will exceed the maintenance criteria by only an extremely slight amount 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 contribution and interference
with maintenance of the annual PM 2.5 NAAQS in Birmingham. For these reasons, EPA does not believe that the more refined air quality modeling for
the annual PM 2.5 standard changes any of EPA’s conclusions with respect to reductions required to eliminate significant contribution and interference with 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 PM 2.5 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 PM 2.5 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 PM 2.5 NAAQS.

EPA has completed some preliminary analysis of the difference between the air quality assessment tool and CAMx results ( see the TSDs ‘‘ 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 accurately reflects the complex nature of the winter portion of the 24-hour PM 2.5 problem. Unlike summer days, for which sulfate
is the dominant contributor to PM 2.5 , sulfate concentrations are typically a
lesser contributor to the overall PM 2.5 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 emissions than for summer 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 NO X , 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. 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 requesting 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 assessment
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


### 45284 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

60 While Colorado is also a state that may see projected increases in emissions, it was not within the domain the EPA analyzed. maintenance problems after the implementation of the 2012 reductions.

EPA also notes that during the winter,

PM 2.5 contains a larger nitrate component than in summer months.

One reason for this is that some nitrates 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 on 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 comment 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 Increases in Noncontributing States

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 increases 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 percent thresholds). Such changes are possible in part because of
the interconnected nature of the country’s energy system (including both the electricity grid and coal and natural gas supplies). In addition, our models project that the rule affects the cost of 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 higher 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. 60 For reference, we also include
the statewide 2012 base case emissions
from all sources within the state.



### T ABLE 

### IV.D–6—U NREGULATED 

### S TATES 

### W ITH 

### M ORE 

### T HAN 

### 5,000 T ONS OF 

### P ROJECTED 

### SO 2 

### I NCREASES 

### U NDER THE 

### P ROPOSED 

### T RANSPORT 

### R ULE

State 2012 SO 2 increase from base case (thousand

tons) 2012 SO 2 base case emissions

from all

sources (thousand

tons)

Arkansas ....................................................................................................................... ........................................... 32 127 Mississippi .................................................................................................................... ............................................ 18 80
North Dakota ................................................................................................................... ......................................... 11 94
South Dakota ................................................................................................................... ........................................ 6 26
Texas .......................................................................................................................... ............................................. 136 640

Further analysis with the 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 μ g/m 3 threshold for
annual PM 2.5 . For this reason, EPA takes
comment on whether Texas should be included in the program as a group 2

state.

(h) Providing Downwind States Full 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 PM 2.5 standard, it may not fully address the
24-hour PM 2.5 standard. Where this may be the case, as explained previously, EPA’s air quality modeling shows thatthe remaining component of nonattainment is almost entirely 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, 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 of 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

PM 2.5 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

PM 2.5 problem sites.

(3) Identification of another pollutant that should be considered part of significant contribution and interference
with maintenance for states that


### 45285 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

61 This is possible where: (1) Latest monitoring
data indicate attainment of the 1997 ozone standard, (2) the area is operating under one-year extensions of their 2009 deadline, or (3) EPA has not made a formal finding of failure to attain. 62 In the case of PM 2.5 , under subpart I, areas can qualify for an extension beyond 5 years, to as many as 10 years, based on certain statutory criteria. contribute to the residual 24-hour PM 2.5 problem sites.

(4) Determination that the reductions proposed 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 proposal, 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 emissions reductions are required or that the
amount of emissions of SO 2 and NO X 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 significantly
contribute to or interfere with maintenance of the 2006 daily PM 2.5 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 could 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 emissions reductions would likely involve placing reduction requirements on sources other than EGUs and that additional approaches
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 anticipated 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 states’ 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 significant contribution. For some aspects of the methodology, further work is needed to complete the methodology for ozone and this further work will be completed in a separate proposal. (1) Years for Quantifying Significant
Contribution

In this subsection, we discuss how EPA identifies for ozone the years to analyze for eliminating significant contribution. Similar to the previous
discussion for PM 2.5 , EPA believes that the selection of the year for eliminating significant contribution is informed by the 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 any 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 contribution, 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 consistent with statutory provisions calling for downwind states to achieve

attainment ‘‘ as expeditiously as practicable. ’’ This also is relevant for
certain other areas with lower ozone classifications that are projected in our analysis to have continuing air quality problems and to be affected by transported pollution from certain upwind states in amounts greater than the 1 percent threshold. 61

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 reductions 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 promulgated, transport requirements would be in place 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 would 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 problems 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). 62 In addition, two 1-year attainment date 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.

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 previously, 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 examine 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,


### 45286 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

63 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). is classified as ‘‘ severe. ’’ For Houston, it is relevant to consider both that (1) the latest permissible attainment date for severe areas is June 2019, which would require emissions reductions by 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 2012 to 2018 time period for this analysis.

(2) Step 1. Emissions Reductions Cost
Curves for EGU Ozone Season NO X

Using IPM, EPA developed cost
curves for 2012 for ozone season NO X , showing the ozone season (May– September) NO X reductions available in
2012 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 addon equipment. Some highly effective and widely employed NO X control 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, 63 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 Call) 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 $500/ton in 2012. There were very few emissions
reductions available below this cost.



### T ABLE 

### IV.D–7—2012 O ZONE 

### -S EASON 

### NO X 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS FOR 

### E ACH 

### S TATE AT 

### V ARIOUS 

### C OSTS 

### (2006$) PER 

### T ON 

### (T HOUSAND 

### T ONS 

### )

Marginal cost per ton $0 $500 $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 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 7 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 discussed in section IV.D.3 later,

little or no ozone season NO X reductions are available for non-EGU sources from control measures costing (at or below) $500/ton. The ozone

season NO X cost curves in Table IV.D– 7 include EGU reductions only. EPA believes that for costs at or below $500/ ton, these curves include all available reductions (because only EGUs have substantial reduction opportunities at or below $500/ton), but for greater costs

the curves do not include all available reductions as they do not include nonEGU reductions.

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, to 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 capabilities 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


### 45287 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 reductions 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.



### T ABLE 

### IV.D–8—2014 O ZONE 

### -S EASON 

### NO X 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS FOR 

### E ACH 

### S TATE AT 

### V ARIOUS 

### C OSTS 

### (2006$) PER 

### T ON 

### (T HOUSAND 

### T ONS 

### )

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

Arkansas .......................................................................... 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 37 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 Assessment of
Potential 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
state’s contribution to downwind ozone levels. For example, if a given upwind
state reduced its ozone season NO X 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 this 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 mobile 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.



### T ABLE 

### IV.D–9—E STIMATED 

### N UMBER OF 

### R EMAINING 

### N ONATTAINMENT OR 

### N ONATTAINMENT AND 

### M AINTENANCE 

### M ONITOR 

### S ITES IN 

### 2012 AND 

### 2014 AS A 

### F UNCTION OF 

### O ZONE



### - SEASON 

### NO X 

### C OST PER 

### T ON 

### L EVELS

2012 2012 2014 2014

Marginal Cost per Ton Number of Remaining Nonattainment 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.


### 45288 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

(4) Step 3. Selection of Cost Thresholds, Taking Into Account Cost and Air Quality Considerations

Using the multi-factor cost and air quality methodology described in section IV.D.1, EPA identifies, for a number of states, the 2012 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 for 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 sources to install 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

NO X 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 NO X reductions in existing rules or available from technologies in various sectors, 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 contribute 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/ton threshold would become approximately $3,200 per ton. As a result, EPA believes 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 Considerations

Using 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 reductions 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 possible 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. 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 Cost Threshold for Ozone

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 threshold 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, the $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 significant 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 corresponding 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 NO X controls greater than $500/ton, and to examine facts involving Houston and Baton Rouge, to support a complete determination of significant
contribution and interference with
maintenance for states that contribute to
one or both of those areas. Based on the analysis done for today’s proposal, EPA believes that any additional NO X reduction requirements would involve reductions from sources beyond 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 information to address these sources beyond EGUs 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 does 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
interference with maintenance as quickly as possible.

(5) Request for Comment Concerning New York City and Contributing States

As in the case of PM 2.5 , 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 air quality analysis, conducted with the CAMx model, can be compared to the results using the air quality assessment tool. The CAMx modeling demonstrated that the


### 45289 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

64 Identification and Discussion of Sources of Regional Point Source NO X and SO 2 emissions other than EGUs. EPA/OAQPS and CAMD. January

2004.

65 Reference: NESCAUM Applicability and Feasibility of NO X , SO 2 , and PM Emissions Control Technologies for Industrial, Commercial, and Institutional (ICI) Boilers. NESCAUM, November 2008. pp. xvii, 3–12–13. 66 U.S. EPA. Petroleum Refinery National Priority
Case Results. Available at http://www.epa.gov/ compliance/resources/cases/civil/caa/oil/index.
html.

67 U.S. EPA. Acid Plant NSR Enforcement Priority. Available at http://www.epa.gov/ compliance/civil/caa/acidplant-nsr/index.html. 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 continue to
have nonattainment/maintenance
concerns even with the reduction of

NO X emissions that could be reduced for (at or below) $500/ton. The modeling
also showed that the locations within the New York City nonattainment area
would continue to have a maintenance problem despite the modeled reductions (including those in New York State). That is, the New York City area is possibly at risk of being innonattainment in light of historical yearto-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, Kentucky, 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 consider
whether and to what 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 Control Costs for
Sources Other Than EGUs

Previously in this section (see discussion in IV.D.2 previously) EPA discusses its proposed cost criteria for identifying SO 2 and NO X 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 PM 2.5 NAAQS. In addition, EPA discusses interim cost
criteria for ozone. Consistent with these criteria, EPA does not believe that other source categories have emissions that are currently significantly contributing to nonattainment or interfering with
maintenance of the 1997 and 2006 PM 2.5 NAAQS. Thus, with respect to the 1997
and 2006 PM 2.5 NAAQS, we are not proposing to include in the FIPs emissions reductions requirements for other source categories.

(a) SO 2 Sources and Costs

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 represents the highest cost value necessary 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 $2,000/ton or less (in year 2006 $).

For the CAIR, EPA included a technical support document 64 which
noted that for SO 2 , EGUs were the 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 highestemitting categories of non-EGU SO 2 emissions are: (1) Industrial, commercial, and institutional (ICI) boilers, (2) Portland cement manufacturing, (3) petroleum refining, and (4) sulfuric acid manufacturing.

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 boilers, 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 NESCAUM 65 suggests scrubber costs are typically 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 year 2003 $). The

LADCO ‘‘ white papers ’’ discussion is available from the following Web site: http://www.ladco.org/reports/control/ final

_ reports/identification

_ 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 at or below $2,000/ton will generally not be available at refineries covered 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. 66

For sulfuric acid manufacturing, the

SO 2 emissions are related to the percent recovery of sulfuric acid product.Because the percent recovery is plantspecific, 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 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
cost 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 realized. 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. 67 More than half of these plants are in states affected by this proposal.

This information shows that few if any SO 2 reductions 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 PM 2.5 transport for the proposed rule. EPA seeks comment on
whether non-EGU emissions reductions should be required and on the specific


### 45290 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

68 Identification and Discussion of Sources of Regional Point Source NO X and SO 2 emissions other than EGUs. EPA/OAQPS and CAMD. January

2004.

69 Reference: Identification and Evaluation of Candidate Control Measures. Phase II Final Report. LADCO, June. 2006. Appendix B.

70 Reference: Assessment of Control TechnologyOptions For Petroleum Refineries in the MidAtlantic Region. Final Report. MARAMA, January
2007. p. 2–24. 71 Reference: NESCAUM Applicability and Feasibility of NO X , SO 2 , and PM Emissions Control Technologies for Industrial, Commercial, and Institutional (ICI) Boilers. NESCAUM, November 2008. pp. xvii, 3–12–13.

72 Reference: Identification and Evaluation of Candidate Control Measures. Phase II Final Report. LADCO, June 2006. Appendix B. 73 Even though allowance prices dropped significantly in 2008 after the Court decision, most sources appear to have continued with the same reduction strategies. control measures that would serve as
the basis for those reductions.

Because sulfur content of both gasoline and diesel fuel are now subject to very stringent sulfur requirements,
EPA believes there are no available onroad and nonroad engine measures to
reduce mobile source SO 2 at or below $2,000/ton.

b. NO X From Non-EGU Sources

For NO X , the methodology described previously in section IV.D.2 requires all
states linked to PM 2.5 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 68 evaluating non-EGU
controls contained a discussion of nonEGU category contributions to the
overall NO X emissions 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 of non-EGU NO X controls
done for the CAIR with a review of the year 2012 inventory. See TSD— ‘‘ NonEGU Emissions Reductions Cost and
Potential. ’’ The highest-emitting stationary source categories of non-EGU

NO X emissions are: (1) Stationary reciprocating internal combustion engines (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 additional
non-EGU controls that can be achieved at $500/ton or less. For example,
available information 69 suggests that costs of various types of NO X controls are greater than this level for non-EGU sources such as ICI boilers, iron and steel mills, petroleum refineries, 70 glass manufacturing plants, and asphalt manufacturing plants. For industrial boilers, a recent report prepared by NESCAUM 71 suggests NO X control costs are typically well above $500/ton for ICI boilers. In addition, a recent report prepared by LADCO 72 indicated

NO X 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), including 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 or below $500/ton.

EPA has not identified further controls for stationary nonpoint sources
or mobile source NO X measures that have costs at or below $500 per ton.

E. State Emissions Budgets

As described 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 significant
contribution and interference with
maintenance 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 remedy ( 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 fossilfuel-fired generation was needed), the
emissions that would remain after significant contribution 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 State Emissions Budgets for EGUs

For group 1 states required to make deeper emissions 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. 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 through (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built by 2012 and (3) the use of low sulfur coal. Because those strategies were already being applied in most states covered by this rule in 2009, 73 EPA believes that the actual 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 only 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 emissions
from the unit to account for the new
scrubber.

For 2012 NO X 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


### 45291 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

74 The impact of variability on the budgets is discussed in section IV.F, later. represents reductions from turning on
SCR units. EPA believes that instead of defining the budgets based on IPM projections of 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 input, historical emissions rates, and, where new SCR units are expected between now and 2012, projected emissions rates
for those new SCR units. The emissions budgets developed using the previous methodology are as follows in Table

IV.E–1:



### T ABLE 

### IV.E–1—SO 2 AND 

### A NNUAL 

### NO X 

### S TATE 

### E MISSIONS 

### B UDGETS FOR 

### E LECTRIC 

### G ENERATING 

### U NITS 

### B EFORE 

### A CCOUNTING FOR 

### V ARIABILITY 74

[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 85,717 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 7,902 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 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 Ozone Season NO X State Emissions Budgets for EGUs

Ozone season NO X budgets were developed the same way as the annual

NO X budgets were developed (explained in IV.E.1, previously).



### T ABLE 

### IV.E–2—O ZONE



### - SEASON 

### NO X 

### S TATE 

### E MISSIONS 

### B UDGETS FOR 

### E LECTRIC 

### G ENERATING 

### U NITS 

### B E



### FORE 

### A CCOUNTING FOR 

### V ARIABILITY

[Tons]

State NO X ozone season, all

years

Alabama .................................... 29,738 Arkansas ................................... 16,660 

### T ABLE 

### IV.E–2—O ZONE



### - SEASON 

### NO X 

### S TATE 

### E MISSIONS 

### B UDGETS FOR 

### E LECTRIC 

### G ENERATING 

### U NITS 

### B E



### FORE 

### A CCOUNTING FOR 

### V ARIA



### BILITY 

### —Continued

[Tons]

State NO X ozone season, all

years

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 ................................ 16,530 New Jersey ............................... 5,269 New York .................................. 11,090 North Carolina .......................... 23,539 Ohio .......................................... 40,661 

### T ABLE 

### IV.E–2—O ZONE



### - SEASON 

### NO X 

### S TATE 

### E MISSIONS 

### B UDGETS FOR 

### E LECTRIC 

### G ENERATING 

### U NITS 

### B E



### FORE 

### A CCOUNTING FOR 

### V ARIA



### BILITY 

### —Continued

[Tons]

State NO X ozone season, all

years

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


### 45292 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

reductions requirements in this rule, as May through September. We recognize that 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 Including Variability

In this section, EPA discusses the inherent variability in electric power system operation and presents proposed variability limits for each state. As explained below, EPA proposes to calculate 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 address years in which more fossil generation occurs than projected in the average base case year. This section also presents projected
emission reduction results.

1. Variability

a. Introduction to Power Sector Variability

Historically, power sector emissions have 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 regulation.

Even when emissions rates do not change from year to year, overall emissions can change because of factors including power demand, timing of maintenance activities, and unexpected
shutdowns of units. Extreme 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, generation, and the routine operation of power plants to supply our electricity, and thus affect
total emissions.

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 emissions 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 this proposal are eliminated. This
occurs even when the emissions rates of the units within the state do not change. For this reason, EPA has determined that it is 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

maintenance.

For the proposed rule, EPA proposes to factor this variability explicitly in its
consideration of how to control emissions. The Agency believes that because baseline emissions are variable,
emissions after the elimination of all significant contribution 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. Because 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 emissions rate-based ‘‘ direct
control ’’ options 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 interference with maintenance. Thus, emissions may vary somewhat after implementation of
the remedies under consideration.
Under an emissions rate-based approach, emissions 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 emissions 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 increase 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 about 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

‘‘ significant contribution. ’’ As noted previously, even if the emissions result is variable 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 significant 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. It is also worth noting that in the proposed State Budgets/Limited Trading remedy, variability 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 statespecific budgets absent variability,
would ensure that total emissions do not increase. This remedy, therefore, ensures not only that total emissions do not increase above state budgets, but
also that reductions occur in each and every state.

b. How EPA Accounted for Inherent Power Sector 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


### 45293 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

75 The two-tailed 95th percent confidence level is the equivalent of the 97.5th upper (single-tailed)
confidence level. 76 Moore, David S. and George P. McCabe. Introduction to the Practice of Statistics. 2nd ed. New York: W.H. Freeman and Company, 1993. p.

395. 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 emissions 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 goals of this analysis, therefore, are to determine the typical variability in emissions that is due to changes in generation, and not 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 interference 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 state-level heat input over a 7-year time period (2002 through 2008) using the standard deviation and
then determined the difference inemissions from the 95th percent twotailed confidence level and the mean. 75 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 percentage 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 level pairing to apply to all states in order to make the application of the variability limits straightforward rather than developing state-by-state percentage variability values. The effect of the pairing is to ensure that each state is allowed adequate variability while minimizing the total amount of emissions allowed. Using, for all states, only a constant percentage (reflecting emissions variability in smaller states with a greater range of emissions in percentage terms) would result in large states being allowed greater variability than needed. Conversely, using only a constant tonnage (reflecting emissions variability in larger states with a greater range of emissions in tonnage terms) would result in small states being allowed greater variability than needed. To ensure adequate variability limits—
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 serve 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 tonnage 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. Power 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 the chosen limits would not be tighter than these states could be expected to meet.

This approach (identifying both a tonnage 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 change in statewide

emissions.

For both annual NO X and SO 2 , the percentage variability limits are 10 percent of a state’s budget and the 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 SO 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 IV.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 variability in 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 this notice be
eliminated.

While the year-to-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 variability 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 emissions 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 variability. The 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-year 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 divided by the


### 45294 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 some 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 IV.F.2, later. See the Power Sector Variability TSD for more details on EPA’s variability approach.

2. State Budgets With Variability Limits

As explained previously, EPA determined variability limits for each state. EPA then applied these variability limits on a state-by-state basis to calculate state-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 21 and 28 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 21 or 28 percent, for NO X and SO 2 , respectively. Because no state varied more than these percentages, EPA believes they could serve as reasonable caps on variability limits. These limits would address the issue of small states receiving very large variability limits as a fraction of their budgets.

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 28 percent of the budget (857 tons). Therefore, under this alternative calculation method, Connecticut’s 1-year SO 2 variability limit would be 857 tons (28 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 21 percent of the budget (583 tons). Therefore, under this alternative approach, Connecticut’s 1-year annual NO X variability limit
would be 583 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.



### T ABLE 

### IV.F–1—V ARIABILITY 

### L IMITS ON 

### SO 2 

### A NNUAL 

### E MISSIONS FOR 

### 2014 AND 

### L ATER FOR 

### E LECTRIC 

### G ENERATING 

### U NITS

[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 1,700 981 857 49 5 Delaware .................................................................................................. 7,784 1,700 981 1,700 981 District of Columbia .................................................................................. 337 1,700 981 94 54 Florida ...................................................................................................... 161,739 16,174 9,3 38 16,174 9,338 Georgia .................................................................................................... 85,717 8,572 4,949 8 ,572 4,949 Illinois ....................................................................................................... 151,530 15,153 8 ,749 15,153 8,749 Indiana ..................................................................................................... 201,412 20,141 11,6 29 20,141 11,629 Iowa ......................................................................................................... 86,088 8,609 4,970 8,609 4,970 Kansas ..................................................................................................... 57,275 5,728 3,307 5 ,728 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 15,568 8,988 Minnesota ................................................................................................ 47,101 4,710 2,719 4,7 10 2,719 Missouri .................................................................................................... 158,764 15,876 9,16 6 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 4,2 04 2,427 North Carolina .......................................................................................... 81,859 8,186 4,726 8,18 6 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 4,079 2,355 4,079 2,355 West Virginia ............................................................................................ 119,016 11,902 6,871 1 1,902 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) 1,700 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 28 percent of the state’s budget. If 1,700 tons is greater than 28 percent of the state’s budget, the state’s limit is set at 28 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.


### 45295 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.F–2—V ARIABILITY 

### L IMITS ON 

### NO X 

### A NNUAL 

### E MISSIONS FOR 

### 2014 AND 

### L ATER FOR 

### E LECTRIC 

### G ENERATING 

### U NITS

[Tons]

State NO X annual 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 2,887 583 336 Delaware .................................................................................................. 6,206 5,000 2,887 1,3 03 752 District of Columbia .................................................................................. 170 5,000 2,887 36 21 Florida ...................................................................................................... 120,001 12,000 6,9 28 12,000 6,928 Georgia .................................................................................................... 73,801 7,380 4,261 7 ,380 4,261 Illinois ....................................................................................................... 56,040 5,604 3,2 35 5,604 3,235 Indiana ..................................................................................................... 115,687 11,569 6,67 9 11,569 6,679 Iowa ......................................................................................................... 46,068 5,000 2,887 5,000 2,887 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 3, 579 2,066 Massachusetts ......................................................................................... 5,960 5,000 2,887 1,252 7 23 Michigan ................................................................................................... 64,932 6,493 3,749 6 ,493 3,749 Minnesota ................................................................................................ 41,322 5,000 2,887 5,0 00 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 2,48 3 1,434 New York ................................................................................................. 23,341 5,000 2,887 4,9 02 2,830 North Carolina .......................................................................................... 51,800 5,180 2,991 5,18 0 2,991 Ohio ......................................................................................................... 97,313 9,731 5,618 9,731 5,618 Pennsylvania ............................................................................................ 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 5,00 0 2,887 Virginia ..................................................................................................... 29,581 5,000 2,887 5,000 2,887 West Virginia ............................................................................................ 51,990 5,199 3,002 5,1 99 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 21 percent of the state’s budget. If 5,000 tons is greater than 21 percent of the state’s budget, the state’s limit is set at 21 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 NO X 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 NO X annual variability limits described earlier in this section, but adjusted to reflect the
ozone season data.

Using that approach, the resulting ozone season 1-year variability 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 percentage limit, whichever was greater for that state—using the same approach as for the SO 2 and NO X 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 NO X annual limits.
The NO X ozone season limits resulting from this approach are shown in Table

IV.F–3.

EPA did not explicitly model ozone season variability limits because it was
assumed that the NO X annual limits would also serve to limit variability in
the ozone season and that additional constraints were unnecessary. However, a comparison 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 ozone 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.

As with the SO 2 and NO X 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 27 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 Table

IV.F–3.


### 45296 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.F–3—V ARIABILITY 

### L IMITS ON 

### NO X 

### O ZONE 

### E MISSIONS FOR 

### 2014 AND 

### L ATER FOR 

### E LECTRIC 

### G ENERATING 

### U NITS

[Tons]

State NO X ozone

season emissions

budget Proposed Alternative

1-year limit 3-year average limit 1-year limit 3-year average limit

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 1,212 355 205 Delaware .................................................................................................. 2,450 2,100 1,212 662 382 District of Columbia .................................................................................. 105 2,100 1,212 28 16 Florida ...................................................................................................... 56,939 5,694 3,287 5,694 3,287 Georgia .................................................................................................... 32,144 3,214 1,856 3 ,214 1,856 Illinois ....................................................................................................... 23,570 2,357 1,3 61 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 1,9 53 1,127 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 1,423 821 New York ................................................................................................. 11,090 2,100 1,212 2,1 00 1,212 North Carolina .......................................................................................... 23,539 2,354 1,359 2,35 4 1,359 Ohio ......................................................................................................... 40,661 4,066 2,348 4,066 2,348 Oklahoma ................................................................................................. 37,087 3,709 2,141 3,7 09 2,141 Pennsylvania ............................................................................................ 48,271 4,827 2,787 4,82 7 2,787 South Carolina ......................................................................................... 15,222 2,100 1,212 2,100 1,212 Tennessee ............................................................................................... 11,575 2,100 1,212 2,10 0 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 2,2 23 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 27 percent of the state’s budget. If 2,100 tons is greater than 27 percent of the state’s budget, the state’s limit is set at 27 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 what variability limits would apply in 2012 and 2013. The 1-year variability limits

for 2012 and 2013 would be the same as the variability limits 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 variability 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-year 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 average 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 of2014, EPA considered—instead of twoyear average limits on SO 2 emissions in the 15 group 1 states in 2012 and 2013— applying 3-year average limits in these states 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


### 45297 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

years spanning the two budget levels is less straightforward. EPA analyzed this
alternative method for the 15 SO 2 group 1 states and compared results to the results using the 2-year average limits in 2012 and 2013 for these states, and determined that the 2-year average approach is reasonable. See the Power Sector Variability TSD for more
information. Table IV.F–4 includes 1-year and 2-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 ( i.e. , the method that adds a ceiling based on the maximum percentage of variability in historic data, 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.



### T ABLE 

### IV.F–4—2012–2013 O NE 

### - AND 

### T WO 

### -Y EAR 

### V ARIABILITY 

### L IMITS ON 

### SO 2 

### E MISSIONS FOR 

### G ROUP 

### 1 S TATES FOR 

### E LECTRIC 

### G ENERATING 

### U NITS

[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 6,650 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 4,705
North Carolina ................................................................................................................. ......................... 111,485 11,149 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 7,260 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-year 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 28 percent of the state’s budget. If 1,700 tons is greater than 28 percent of the state’s budget, the state’s limit is set at 28 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, because for each of these budgets, 1,700 tons is less than 10 percent of the budget.

3. Summary of Emissions Reductions
Across All Covered States

Table IV.F–5 presents projected power sector emissions in the base case ( i.e. , without the proposed Transport Rule or CAIR) compared 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.



### T ABLE 

### IV.F–5—P ROJECTED 

### SO 2 AND 

### NO X 

### E LECTRIC 

### G ENERATING 

### U NIT 

### E MISSIONS 

### R EDUCTIONS IN 

### C OVERED 

### S TATES 

### W ITH THE 

### T RANSPORT 

### R ULE 

### C OMPARED TO 

### B ASE 

### C ASE 

### W ITHOUT 

### T RANSPORT 

### R ULE OR 

### CAIR

[Million tons]

2012 base

case emissions 2012 transportrule emissions 2012 emissions reductions 2014 base

case emissions 2014 transportrule 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

**Note:** Emissions differ from emissions budgets due to banking.



### T ABLE 

### IV.F–6—P ROJECTED 

### SO 2 AND 

### NO X 

### E LECTRIC 

### G ENERATING 

### U NIT 

### E MISSIONS 

### R EDUCTIONS IN 

### C OVERED 

### S TATES 

### W ITH THE 

### T RANSPORT 

### R ULE 

### C OMPARED TO 

### 2005 A CTUAL 

### E MISSIONS

[Million tons]

2005 actual emissions 2012 transportrule emissions 2012 emissions reductions from 2005 2014 transportrule emissions 2014 emissions reductions from 2005

SO 2

.......................................................................................................... 8.9 3.4 5.5 2.6 6.3


### 45298 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IV.F–6—P ROJECTED 

### SO 2 AND 

### NO X 

### E LECTRIC 

### G ENERATING 

### U NIT 

### E MISSIONS 

### R EDUCTIONS IN 

### C OVERED 

### S TATES 

### W ITH THE 

### T RANSPORT 

### R ULE 

### C OMPARED TO 

### 2005 A CTUAL 

### E MISSIONS 

### —Continued

[Million tons]

2005 actual emissions 2012 transportrule emissions 2012 emissions reductions from 2005 2014 transportrule emissions 2014 emissions reductions from 2005

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 Proposed Approach Is Consistent With Judicial Opinions Interpreting Section 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 DC
Circuit. As discussed in section III previously, the DC Circuit has issued two significant decisions addressing the requirements of 110(a)(2)(D)(i)(I). The first opinion largely upheld the NO X SIP Call, Michigan v. EPA, 213 F.3d 663 (DC Cir. 2000), and the second found significant flaws in the CAIR, North
Carolina v. EPA, 531 F.3d. 896 (DC Cir. 2008). In both cases, the Court considered aspects of the methodology used by EPA to identify emissions that, pursuant to section 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 Transport Rule is consistent with both opinions and
rectifies the flaws the North Carolina Court identified with the methodology used in CAIR. The methodology usedfor this proposed rule relies on statespecific data to analyze each individual state’s significant contribution, uses air quality considerations in addition to cost considerations to identify 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-specific analysis of significant contribution. See id. at 907. EPA, the Court concluded, ‘‘ never measured the ‘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 uses a first step similar to that used in the CAIR to identify the states with relatively large contributions. However, in contrast to the CAIR, it then uses a state-specific analysis. Instead of identifying a single emissions level that could be achieved by the application of highly cost effective controls in theregion, EPA determines, on a state-bystate 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 is then divided into state budgets that set the emission reduction requirements for each state. Instead, EPA develops, 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 electric generating system. The selected cost/ton
levels reflect consideration of both cost factors and air quality factors including the estimated impact of upwind states’ emissions on each downwind receptor.

In addition, in developing this approach, EPA was guided 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 corresponding 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 states. 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 line 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 regarding the use of cost and
a uniform cost-criterion across states
were left undisturbed. See, e.g., North Carolina, 531 F.3d at 917 (explaining that in Michigan the 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 individualized 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 Carolina, 531 F.3d at 918. Thus, in this rulemaking, EPA departs 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-cost-effective. ’’ Instead, as part of its determination of a reasonable cost per ton for upwind state control, EPA evaluates the air quality impact of reductions at various
cost levels and 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


### 45299 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

77 Certain non-EGUs and smaller EGUs were
included in the CAIR NO X 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. ‘‘ gave no independent significance to the ‘interfere with maintenance’ prong of section 110(a)(2)(D)(i)(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 identifying downwind

‘‘ nonattainment sites ’’ and downwind

‘‘ maintenance sites. ’’ EPA decided to consider upwind states’ contributions not only to sites that EPA projected would be in nonattainment, but also to sites that, based on the historic variability of their 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 PM 2.5 , this approach identified
16 maintenance sites in addition to the
32 nonattainment sites identified in the analysis of nonattainment receptors. For
24-hour PM 2.5 this approach identified
38 maintenance sites in addition to the
92 nonattainment sites identified in the analysis of 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 significantly
contribute to nonattainment or interfere
with maintenance in downwind areas with regard to the 1997 and 2006 PM 2.5 NAAQS and the 1997 ozone NAAQS. Although EPA has not completely quantified the total significant contribution of these states with 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, elimination 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 Proposed

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.

EPA evaluated approaches 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 μ g/m 3 ), and binning of states based on air quality impact. Detailed descriptions of the alternative 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 FIPs that would implement the emissions reductions, and explaining the structure and key elements of the proposed Transport Rule trading program rules for 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 NO X because of their impact on downwind states’ ability to attain and
maintain the PM 2.5 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 Categories

EPA is proposing to require emissions reductions from the power sector. This
section discusses EPA’s rationale for 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 capacity greater than 25 MWe in the covered
states to reduce emissions of SO 2 , NO X , 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 NO X emissions. In 2012, 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 emissionsand about 20 percent of the total manmade NO X 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

EPA has previously conducted extensive analyses of the cost and emissions impacts of SO 2 and NO X 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 alsoanalyzed several power sector multipollutant scenarios in July 2009 at the request of Senator Tom Carper. These analyses are on EPA’s Web site at: ( http://www.epagov/airmarkets/ progsregs/cair/multi.html ). EPA’s IPM analysis for CAIR is another example: ( http://www.epagov/airmarkets/ progsregs/epa-ipm/cair/index.html ).

Based on these analyses, EPA believes
that there exist reasonable means for
EGUs to make substantial reductions in
emissions of SO 2 and NO X . EPA also believes that, at this time, EGUs can


### 45300 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

79 See section IV.D.3 for discussion of non-EGUs

that were included in the CAIR NO X ozone season trading program. 80 Section 172(a)(2) of the Clean Air Act provides

that ‘‘ the attainment date for an area designated nonattainment with respect to a national primary ambient air quality standard shall be the date by which attainment can be achieved as expeditiously as practicable, but no later than 5 years from the date such area was designated nonattainment under section 7407(d) of this title, except that the Administrator may extend the attainment date to

the extent the Administrator determines appropriate, for a period no greater than 10 years from the date of designation as nonattainment, considering the severity of nonattainment and the availability and feasibility of pollution control

measures. ’’ Designations for the 2006 24-hour PM 2.5 NAAQS became effective on December 14, 2009. reduce SO 2 and NO X emissions more cost-effectively than other source categories ( see section IV.D for

discussion of control costs for non-EGU source categories). For these reasons, EPA has decided to require reductions

in SO 2 and NO X emissions from EGUs in the FIPs in this proposed rule. EPA requests comments on these proposed FIPs and its proposal to require

reductions from 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 From Other Source Categories To Address Transport Requirements for PM 2.5

In the proposed FIPs to address the section 110(a)(2)(D)(i)(I) requirements with respect to the 1997 and 2006 PM 2.5 standards, EPA proposes to regulate only emissions from EGUs. As discussed previously in section IV.D,

EPA’s review of the costs of EGU and

non-EGU controls resulted in a

conclusion that substantial SO 2 and

NO X reductions from EGUs 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

demonstrated 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 PM 2.5 NAAQS in downwind areas. This same section explains that EGU reductions substantially address eliminating the quantity of emissions identified by EPA as significantly contributing to or interfering with

maintenance of the 2006 PM 2.5 NAAQS, and this same section explains the need for EPA to further analyze remaining

winter PM 2.5 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 nonEGU sources in order to eliminate significant contribution and interference with maintenance for any other NAAQS, including the 1997 ozone NAAQS and future NAAQS for PM 2.5

. 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 non-EGU 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 non-EGU NO X controls. The same section also explains the need for EPA to further analyze whether fully addressing upwind state 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 PM 2.5 NAAQS, EPA intends to quantify the emissions reductions needed to 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. Sources will be required to comply with the annual SO 2 and NO X requirements by January 1, 2012 and January 1, 2014 for the first and second phases, respectively. Similarly, sources will be required to comply with the

ozone season NO X requirements by May 1, 2012, and by May 1, 2014. EPA chose

these dates to coordinate with the NAAQS attainment deadlines and to

assure that reductions 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 reductions to address the NAAQS in the future. 1. Date for Prohibiting Emissions That Significantly Contribute or Interfere

With Maintenance of the PM 2.5 NAAQS

For all areas designated as nonattainment with respect to the 1997

PM 2.5 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 PM 2.5 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 PM 2.5 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. 80

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 PM 2.5 NAAQS. These reductions will also help areas meet the December 2014 attainment deadline with respect to the

2006 PM 2.5 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 further discussion in section IV.D).


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81 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 a.m. to 8 p.m.) during 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. 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 corresponding 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 2009 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 With 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
contribution 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, will replace the CAIR, EPA
cannot assume that after this rule is finalized, EGUs would continue to emit
at the reduced emissions levels achieved by CAIR. Instead, it is the emissions reductions requirements in the proposed FIPs that will determine
the level of EGU emissions in the eastern United States. For these reasons, EPA is proposing to require an initial phase of reductions by 2012 which would ensure that existing and planned

SO 2 and NO X controls operate as anticipated. 4. How Compliance Deadlines Address the Court’s Concern About Timing

As directed by the Court in North
Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008), and described previously, EPA has established the compliance deadlines in the proposed rule based on the respective NAAQS attainment requirements 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 nonattainment areas (taking into account the need for reductions by 2012 to demonstrate attainment by that date). This deadline is also consistent with 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 PM 2.5 NAAQS (taking into account the need for reductions by 2014 to demonstrate 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 PM 2.5 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 emissions
reductions will assure the reductions are achieved as expeditiously as practicable. EPA established the interim 2012 compliance deadline for annual

NO X and annual SO 2 reductions because a significant number of reductions can be achieved by 2012. However, given the time needed to design and construct 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. Requiring 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 provide for attainment as expeditiously as practicable and within the applicable
maximum deadlines.

5. EPA Will Consider Additional Reductions in Pollution Transport To Assist in Meeting Any Revised or New NAAQS

a. Ozone

As noted, in a January 19, 2010, notice 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. 81

EPA expects to finalize the 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 those standards and will evaluate and analyze the impact of upwind state emissions in those areas with regard to those standards. EPA has already begun the technical background 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 analysis 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 PM 2.5 NAAQS. This review is scheduled for completion in October 2011. EPA plans


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to conduct background technical analyses so that EPA will be prepared to move quickly, if necessary, with a transport rule related to any revised

PM 2.5 NAAQS.

D. Implementing Emissions Reductions Requirements

In this rule, EPA is proposing FIPs to eliminate the significant contribution
and interference with maintenance EPA
has identified in this action. We are proposing one ‘‘ remedy ’’ option to implement the necessary emissions reductions and taking comment on two other options. Before presenting these options we briefly summarize the approaches used in the NO X 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 provided 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 PM 2.5 NAAQS.

NO X SIP Call approach. The NO X 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 upwind NO X emissions can contribute significantly to
ozone nonattainment 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 Performance 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 established 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.

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 under 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 included 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 represents one ton of NO X 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 reduced 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, sources use continuous emission monitoring systems (CEMS) or other approved monitoring methods under EPA’s stringent monitoring requirements (Title 40 of the Code of Federal Regulations [CFR], Part 75).

The NO X SIP Call cap and tradeprogram was a way to make costeffective 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 NO X 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 boilers 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 identified 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 Program, was phased in starting in 2003 for the OTC states, with the majority of affected states participating
as of 2004.

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 PM 2.5 and 8-hour ozone NAAQS in downwind states. The EPA required these 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 PM 2.5 and 8-hour ozone
nonattainment areas achieve the NAAQS. Moreover, reducing upwind emissions 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 cap and trade programs,
which were similar to the SO 2 trading program in Title IV of the CAA and the

NO X Budget Trading Program in the

NO X SIP Call. CAIR required implementation of emissions reductions requirements for SO 2 and NO X in two phases. 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 2 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

NO X emissions for PM 2.5 , 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


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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 final 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 DC Circuit.

In Michigan v. EPA , 213 F.3d 663, the Court largely upheld the NO X SIP Call. The portion of this 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, regardless of amount of contribution, reduce their NO X by an
amount achievable with ‘‘ highly costeffective 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 id . 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 air 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 challenged 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 emission 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 state 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
contribution. See id . 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 do 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). While 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. Furthermore, since CAIR was designed as a ‘‘ complete remedy to section 110(a)(2)(D)(i)(I) problems ’’ the Court emphasized that ‘‘ it must actually require elimination of emissions from sources that contribute significantly and
interfere with maintenance. ’’ Id . at 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 the definition of significant
contribution. See North 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 emissions reductions 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. Stakeholders have suggested a variety of remedy options for EPA’s consideration.
A TSD in the docket entitled ‘‘ Other Remedy Options Evaluated ’’ describes other options that EPA evaluated.

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 NO X 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 PM 2.5 NAAQS and the 8-hour ozone NAAQS.

The remedy option EPA is proposing would use state-specific 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 Court 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 on consideration of a range of options, EPA believes that the proposed option is the best approach, for the reasons discussed

in section V.D.4.

The Agency is also presenting other
alternative remedies for comment. The first alternative for which EPA requests comment would use state-specific control budgets and allow intrastate trading of emissions allowances allocated to EGUs, but no interstate


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82 Note that the report evaluating this alternative was a theoretical economic and air quality analysis of the concept. It did not explore how trading ratios would be incorporated into a workable trading program. It did however indicates that the

‘‘ approach also provides for the possibility that the emission weights developed by this analysis could be incorporated into an emission trading program in which emission weights act like exchange rates between different subregions and species. However this adds a significant increase in the complexity of the market and in practical terms is worth considering only when the potential cost savings are large enough to offset the additional complexity
in market structure. ’’ P. 1–7, Stratus Consulting Inc. November 24, 1999. trading. The second alternative for which EPA requests comment is a direct control program in combination with state-specific control budgets.

EPA recognizes there could be cost savings from an approach that uses aless restrictiveinterstate trading option. EPA also recognizes that unrestricted trading programs including the NO X SIP Call Trading Program have been very successful in addressing regional pollution problems.

In this action, EPA is not proposing such an unrestricted trading program,
because EPA does not believe that such an option could provide assurance that
each state achieves emissions reductions within the state, as required by the North Carolina decision. As the D.C. Circuit emphasized in its opinion, the statutory requirement in section 110(a)(2)(D)(i)(I) aims to prohibit

‘‘ sources ‘‘ within the State ’’ from contributing to nonattainment or interfering with maintenance in ‘‘ any other State. ’’ North Carolina , 531 F.3d at
908. The location of emission
reductions is relevant because it can influence where air quality improvements occur and whether a particular state meets its statutory obligations. See North Carolina, 531
F.3d at 907.

In addition to considering unrestricted trading, EPA also
considered whether there were other ways that a trading program could be
structured to address the Court’s concerns. In particular, EPA reviewed a methodology that had been investigated during the development of the NO X SIP Call regulation that used trading ratios ( ‘‘ Development and Evaluation of a Targeted Emission Reduction Scenario
for NO X Point Sources in the Eastern United States: An Application of the Regional Economic Model for Air Quality (REMAQ) ’’ , Prepared by Stratus Consulting inc. November 24, 1999) (at http://www.epagov/airtransport ). This approach would allow interstate trading, but use trading ratios to take
into account differences in the cumulative downwind impact of emissions from different states. Trading ratios would be developed for each pair of states using air quality modeling such that, given the meteorological assumptions underlying the air quality modeling, the ratios would represent the
ratio of the benefit to downwind air quality within a region from controlling emissions in different upwind areas. For instance, in its simplest form, if
emission reductions from State A were twice as effective at reducing cumulative downwind air quality impact on a set of downwind receptors as emission reductions from State B, the trading ratio between States A and B
would be 2 to 1. 82 In other words, if the States chose to trade, State A would have to purchase 2 allocations from
State B to cover 1 ton of State A’s emissions, since State A’s emissions have twice the impact on downwind air quality. Such an approach offers the very valuable potential to address the transport problem in an effective (and potentially less costly) manner, as it incentivizes reductions from the places where they have the greatest value in reducing downwind air quality problems. While it offers such opportunities, there are challenges in developing such a system that is consistent with the requirement under section 110(a)(2)(D) that emission reductions occur in particular geographic locations. The trading ratio approach would be designed to assure a cumulative downwind air quality result, not to assure specific upwind reductions. Although it would reduce the incentive for sources from upwind states with larger cumulative impacts to comply by purchasing allowances (since they would need to purchase a greater number of allowances per ton emitted
than sources in states with less of an impact), as currently contemplated it would not be possible under this approach to include enforceable legal requirements to ensure that a specific
state’s emissions remain below a specified level or to ensure that a specific amount of reductions occur within a particular state. EPA specifically requests comment on whether a ratios trading program could be designed to provide such a legal
assurance. We also seek comment on
whether such an assurance would be needed if, for example, in practice modeling results predicted with confidence that sufficient state-by-state
reductions would be achieved under such an approach.

In the SIP Call, EPA did not ultimately propose this methodology for several reasons. First, the Stratus Consulting study ( ‘‘ Development and Evaluation of a Targeted Emission
Reduction Scenario for NO X Point Sources in the Eastern United States: An Application of the Regional Economic Model for Air Quality (REMAQ) ’’ ) estimated that the most significant cost savings occurred from moving from a uniform direct control approach to a conventional cap-and-trade approach (the study suggested that this would lead to cost savings of approximately 25 percent). Adding trading ratios added significant complexity while only very slightly lowering costs (1 percent to 5 percent compared to conventional cap and trade, where the cost savings decreased as the problem being addressed became more widespread ( e.g. cost savings for the more stringent 1997 8 hour ozone NAAQS standard would be less than cost savings for the less stringent early 1 hour standard)) (Stratus, page s–2). However, because the transport rule is a larger program covering multiple pollutants with a
different set of non-attainment areas and a broader geographic scope, there is the potential for greater cost savings. Second, the trading ratios are dependent upon the meteorological assumptions used to develop them; to the extent that future year meteorology or costs turn out to be different, the trading ratios could in fact lead to less than predicted downwind air quality benefits. Notably in reality, the ratios would have to consider that the upwind states that impact a downwind receptor vary from receptor to receptor; conversely each upwind state contributes to different sets of downwind receptors. It would be very challenging to develop trading ratios that account for this myriad of different relationships. EPA believes
these concerns are also valid in the context of this Transport Rule.

In addition, in considering this approach in the original SIP Call, it took close to a year to perform the underlying analysis to develop ratios for 1 pollutant (NO X ) and one downwind air quality problem (ozone). In this context, there are 3 pollutants (annual NO X , annual

SO 2 and ozone season NO X ) and two downwind air quality problems (ozone
and PM 2.5 ) to consider.

EPA requests comment on the trading ratios approach, including whether: The trading ratio approach described above
would be consistent with the Court opinion in North Carolina v. EPA and satisfy the section 110(a)(2)(D) requirement that reductions occur

‘‘ within the state ’’ ; there are ways the approach could be modified to be consistent with the Court opinion and the statutory requirement; there are ways that such an approach could administratively be put in place by 2012 and be modified and adopted if further reductions are required to address


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83 EPA, however, has proposed variability limits to these budgets, and it is possible a ratios approach may imply emissions would fall within the variability limits if the ratios ultimately turned out
to be close to one-to-one. 84 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 Wisconsin. As noted in section III, for purposes of this rulemaking, when we discuss ‘‘ states ’’ we are also including the District of Columbia. future NAAQS; and on whether there are ways that such a system could be designed to be transparent and relatively simple for sources to understand and comply with.

Analysis from the SIP Call suggests that the trading ratios approach might have the potential to slightly reduce costs. However, the approach, as envisioned, appears to be in tension
with EPA’s mandate under section 110(a)(2)(D)(i)(I) to assure that significant contribution is fully addressed in each upwind state. While such an approach would ensure reductions on a region-wide basis, EPA has not been able to identify a way that the trading ratio approach could be modified to assure a specific set of
downwind emissions reductions from all states. Under such an approach, there is the potential that some upwind states might make reductions that are larger than their significant contribution, while other states might
make reductions that are less than their significant contribution. Because the state budgets have been designed to
achieve all reductions available at a given cost, trading ratios other than one to one, although providing equivalent improvements in downwind air quality
would lead to emissions reductions that
were inconsistent with the initial budgets. 83

Because EPA recognizes the potential cost savings and potential improvements in program effectiveness associated with less restricted trading options, EPA is also requesting comment on the appropriateness of the assurance provisions that have been proposed, including whether they are adequate to assure that significant
contribution and interference with
maintenance are addressed in each state, whether they are overly restrictive, and whether there are less restrictive options that would provide adequate assurance that the statutory mandate is satisfied while providing more flexibility. Alternative approaches could potentially include: Using the basic methodology proposed with a higher or lower variability limitation or using an alternative to the approach to assure that state emissions budgets are met ( e.g. , trading ratios designed to assure that certain upwind emission reduction targets are met, rather than trading ratios designed to assure that downwind air quality goals are met). With regards to the variability limits that EPA has proposed, EPA takes comment on alternative approaches to calculating those limits, such as considering confidence intervals different than a 95 percent confidence interval such as a 99 percent confidence interval (For more information see TSD,

‘‘ Power Sector Variability ’’ .)

EPA specifically requests that any commenter suggesting a less restrictive approach address how the commenter’s preferred approach would satisfy the statutory mandate in section 110(a)(2)(D)(i)(I) of the Clean Air Act
and be consistent with the decision of
the DC Circuit in North Carolina v. EPA

, 531 F.3d 8906 (2008) ( e.g. , if commenters suggest a higher variability limitation, what would be the rationale for allowing that amount of variability; if commenters suggest an alternative framework, how would that framework
assure that reductions occur ‘‘ within the

state ’’ ) as well as how EPA could develop the approach in a way that would be workable for sources, states,
and EPA in time to achieve emission reductions in 2012 ( e.g. , would an approach with trading ratios impact transaction costs or be overly complex for less sophisticated trading entities, can the analysis needed to develop the approach be completed in a timely way).

As discussed in section IV.E, EPA is proposing new state budgets 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 proposed 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 the
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
emissions. 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
reductions. A state’s SIP submission to replace the Transport Rule FIP might propose to use any remedy of the state’s choosing that actually eliminates the emissions that significantly contribute
to nonattainment or interfere with
maintenance downwind. Section 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. 84 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 assurance 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 making 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 these assuranceprovisions starting in 2014. Statespecific emissions budgets with variability limits would be established
as described 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


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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 assurance 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 Proposal

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.

To directly eliminate the portion of each state’s significant contribution and
interference with maintenance that EPA has identified in this action, the proposed 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 issued to
sources in each state. Each affected source must hold, and surrender to 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 reduces, 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 FIPs include penalty provisions that are adequate to ensure that the budget including a variability limit will not be
exceeded 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 stringent 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
annual NO X 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 NO X trading programs; Table IV.E–2 lists the states
for the ozone season NO X program.

New emissions allowances based on the new state budgets without variability would be allocated to individual sources, as described later.
Four sets of allowances would be allocated, one for each of the four trading programs (SO 2 group 1, SO 2 group 2, NO X annual, and NO X 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 allowances. 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.
b. How the Proposal Would Be Implemented

(1) Applicability

The requirements in the proposed FIPs 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 thelater of November 15, 1990 or the startup of the unit’s combustion device, 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, petroleum, 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 FIPs (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 system, ’’ 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 electricity through the sequential use of energy. In order to qualify as a cogeneration unit, a unit also must meet, on an annual basis, specified efficiency and operating standards, e.g., 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, useful thermal energy must be no less than a certain percentage of total energy output, and 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 ’’ definition 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


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the efficiency and operating standards every year starting with the first 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 and operating standards every year starting the later of November 15, 1990 or the date on which the unit first produces electricity. EPA
believes this definition of ‘‘ cogeneration

unit ’’ is preferable because it may be problematic to obtain sufficiently
detailed information about unit efficiency and operations for some units ( e.g. , old units that may have started producing 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 efficiency and operation back to November 15, 1990 and whether the efficiency and operating standards
should be limited to even more recent years by requiring that the standards be met every year starting the later of a date ( e.g. , January 1) of a more recent year ( e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity. Second, in CAIR, each unit had to meet individually the efficiency standard (i.e., the requirement that useful thermal or electrical output be at least a specified percentage of energy input). In contrast, under the ‘‘ cogeneration unit ’’ definition proposed here, if thecogeneration system of which a toppingcycle unit (where power is produced first and then useful thermal energy is produced using the resulting waste energy) is a part meets the efficiency standard on a system-wide basis, then
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. EPA requests comment on whether this approach should also be applied to bottoming-cycle units (where useful thermal energy is produced first and then useful power is produced using the resulting waste energy).

As discussed previously, the operating and efficiency standards in
the ‘‘ cogeneration ’’ definition must be met every year. However, EPA is
concerned whether these annual standards should be applied to a calendar year when the unit involved did not operate at all. For such a year, the unit would be unable to meet the operating and efficiency standards but also would not have any emissions. EPA therefore requests comment on whether it should exclude, from the requirement to meet the operating and efficiency standards, calendar years (if any) during which a unit does not operate at all.

If a unit meets the definition of cogeneration unit (including the efficiency and operating standards), 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—starting 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 requests 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 sale) back to November 15, 1990 and whether the electricity sales limit should be restricted to 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, 2005, or 2009) or the start-up of
a unit’s combustion chamber.

Solid waste incineration unit exemption. The proposed FIPs also include 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 not exceed 80 percent. This is the same as
the solid waste incineration unit exemption used in CAIR. EPA requests comment on whether it may be problematic to obtain sufficiently
detailed information about unit operation potentially as far back as
1985–1987 and 1990 and whether the fuel consumption standard for each unit should be limited to 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, 2005, or 2009) or the date on which the unit first produces electricity.

Further, analogous to the approach proposed for the cogeneration unit exemption, the proposed solid waste incineration unit exemption would apply to units that qualify as solid waste incineration units every year starting the later of November 15, 1990 or the date the unit first produces electricity. EPA requests comment on whether it may be problematic to obtain sufficiently
detailed information about whether a unit qualified as a solid waste incineration unit back to November 15, 1990 and whether the qualification requirement should be restricted to more recent years by imposing the qualification requirement every year starting the later of a date ( e.g. , January 1) of a more recent year ( e.g. , 2000, 2005, or 2009) or the date of unit first produces electricity.

EPA also proposes to make explicit in the FIPs 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 natural 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 proposes to include, in the trading programs under the proposed FIP, provisions allowing non-electric generating (non-covered) units to opt into one or more of the proposed trading programs. EPA is proposing opt-in provisions since they could encourage emission reductions by
sources that could make lower cost
emissions reductions than electric generating units. These lower cost reductions could replace higher cost
reductions that would otherwise be required by some electric generating units and could reduce overall program

costs.

Specifically, the proposed opt-in provisions would allow a non-covered unit to enter a proposed trading program voluntarily and obtain an allocation of


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allowances reflecting the unit’s emissions before opting in. Once in the program, the unit could make emissions
reductions at a lower cost than other units in the program and then sell, to covered sources for use in compliance,
allocated allowances that are in excess
of the unit’s reduced emissions. The
allowances created for and allocated to the opt-in unit would be in addition to
the allowances issued from the state budget and would be usable incompliance by any covered unit (or optin unit) just like the allowances allocated from the state budget to covered sources. Replacing higher cost reductions by covered units by lower cost reductions by opt-in units could reduce the overall cost of controlling emissions. EPA requests comment on the benefits and concerns of including opt-in provisions.

The proposed opt-in provisions would establish the following procedures, which are similar to those
set forth in the CAIR FIPs. A unit would be eligible to opt into one of the proposed trading programs if the unit: (1) Is an operating boiler, combustion turbine, or other stationary combustion device; (2) is in a facility that is located in a state subject to that proposed trading program; (3) vents all its emissions through a stack or duct; and (4) would be able to meet the monitoring, reporting, and recordkeeping requirements for covered units under the proposed trading program. The owners and operators, through a designated representative, of a source with a unit seeking to opt in would submit to EPA an opt-in application, which must include an emissions monitoring plan for the unit. If EPA approved the monitoring plan, the unit would operate, monitor, and report emissions in accordance with the monitoring plan and monitoring and reporting requirements under Part 75, for at least one or for up to 3 full calendar years (or full ozone seasons, in the case of an opt-in unit in the proposed NO X ozone season trading program). The unit’s monitored heat input and emissions rate for that period would be the baseline heat input and
baseline emissions rate used in calculating any future opt-in allowance
allocations.

After the monitoring period, EPA would review the opt-in application and either approve the application (including an allowance allocation for the first year of approved opt-in status), effective January 1 (May 1 for the NO X ozone season program) of the year of the approval, or disapprove the application. By December 1 (September 1 for the

NO X ozone season program) of the first year and each subsequent year, EPA would calculate and record the opt-in unit’s allowance allocation for the year. The allowance allocation for the year involved would be the product of: The lesser of the baseline heat input and the opt-in unit’s actual heat input during the control period in the immediately preceding year; and the lesser of the baseline emissions rate multiplied by 70 percent and the most stringent state or federal emissions limitation applicable to the unit (or emissions levels resulting from the imposition of Clean Air Act requirements) any time during the control period in the year involved.

After the opt-in unit was in the program for at least four years, the owners and operators could request to withdraw the opt-in unit at the end of a control period if the unit met the requirement to hold allowances covering emissions for that control period and if any allowances already allocated for a subsequent control period were surrendered. However, the owners and operators could not submit a new opt-in application for the withdrawn unit until at least 4 years after the last control period before the withdrawal. An opt-in unit that had a change in regulatory status during a control period and would then meet the general applicability requirements for covered units would immediately lose its status as an opt-in unit. Having lost its opt-in unit status, the unit would
have to surrender to EPA the allocated opt-in allowances attributable to the portion of any control period during which the unit no longer qualified as an opt-in unit.

In addition to a general request for comment on all aspects of this opt-in requirement, EPA requests comment on three specific aspects of the proposed opt-in provisions. First, EPA requests commenters to explain how much interest they believe owners and operators of noncovered sources would have in using these proposed provisions to opt into one or more of the proposed trading programs and what types of sources would be most likely to opt in. Commenters on this aspect of the proposed provisions should consider what effect (if any) future emission reduction requirements under upcoming, new regulations ( e.g. , regulations concerning maximum available control technology (MACT)
standards for sources such as industrial boilers and cement kilns, best available retrofit technology (BART) requirements for certain stationary source categories, and reasonably available control technology (RACT)) might have on the pool of sources that might be interested in opting into the program. EPA notes that, in the Acid Rain Program, opt-in provisions were established in section 410 of the Act, were implemented in the Acid Rain Program regulations starting in 1995, and, to date, have been used by 4 facilities (plus 2 more facilities that temporarily opted in to obtain
allowances for use in the CAIR SO 2 trading program). In the NO X BudgetTrading Program, EPA promulgated optin provisions that states could include in their SIPs and that were used by
3 facilities.

Second, EPA requests comment on whether it is necessary to take steps to identify in this application process
whether emissions reductions identified by these facilities are reductions units
would not have made for other reasons unrelated to the opt in. Comments on this issue would be especially useful if they discussed how the proposed opt-in provisions could be revised in order to ensure that opt-in units would not be
credited for emissions reductions that the units would make even if they did not opt in. For example, a unit that, for business or other reasons, was already planning to take actions that would have the effect of reducing emissions ( e.g. , fuel switching) may be able to opt in under this proposed approach and
obtain allowance allocations that could be sold to covered units. In that case,
emissions reductions that would have occurred anyway would be offset by the allocation of new, opt-in allowances
that would be in addition to the state budget. The net result, in that case,
would be an increase in total emissions—considering the emissions of both the covered units and the opt-in
unit—over what total emissions would have been if the unit had not opted in. EPA requests comment on whether, in
that circumstance the total emissions reduction still may be sufficient to satisfy the interstate transport issue if such reductions were not anticipated in state budgets. In other words, even if
emissions reductions would have happened in the absence of the program, they may still be reductions that
alleviate attainment or maintenance issues in downwind states. Third, EPA requests comment on whether the
baseline emission rate used todetermine the allocations for each optin unit should be multiplied by 70 percent before EPA compares that rate to the unit’s most stringent applicable
emissions limitation in order to
determine which is lower. The lower
emission rate would then be used in calculating the opt-in unit’s allocation. EPA also requests comment on whether the allocation for an opt-in unit during Phase II of the proposed SO 2 Group 1


### 45309 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

85 Planned units, as identified in the EGU inventory and included in IPM modeling projections, comprise units that had broken ground or secured financing and were expected to be online by the end of 2011. trading program should be reduced by 45 percent, reflecting the average percent reduction in state SO 2 Group 1 budgets from Phase I to Phase II. The 70 percent reduction of the baseline emission rate for all opt-in units, and the further 45 percent reduction in
Phase II allocations for SO 2 Group 1 optin units, would be meant to ensure that opt-in facilities install controls in a similar manner as covered units; however, all things equal, this may
serve to lower the number of facilities that would opt into the program. EPA therefore specifically solicits comment on whether the proposed 70 percent reduction (or some other percentage reduction or no reduction) should applied to the baseline emission rate for all opt-in units and on whether any additional percentage reduction or 45 percent or some other additional percentage reduction should be applied

to SO 2 Group 1 opt-in units on Phase II
in order to strike a reasonable balance between achieving additional reductions per opt-in facility and having more facilities opt in.

Sources equal to or less than 25 MWe
and Non-EGUs. Certain smaller EGUs
and non-EGU sources that were
included in the NO X Budget Trading Program were brought into the CAIR

NO X 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 requestscomment on lowering the greater-than25 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 the SO 2 , annual

NO X , 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). As discussed later, EPA proposes to set aside 3 percent of each state’s emissions budgets for new units.
Tables IV.E.–1 and IV.E.–2 in section IV.E, referenced previously, show the permanent SO 2 , NO X , 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, NO X 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 ton of NO X 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 with these allowance-holding requirements at the source ( i.e. , facility) level.

This section 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 allocations 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 implementation of the proposed FIPs),
and after deductions for the new unit set
asides. Section IV.E describes 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 believes 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 Court 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 detail 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 described in the Applicability section, previously ( see 4.b), that commenced commercial operation, or are planned 85 to commence commercial operation, prior to January 1, 2012. EPA proposes that, for 2012, each existing unit in a given
state receives allowances commensurate
with the unit’s emissions reflected 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 proposes 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.

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. Further details on the proposed allocation method for existing units can
be found in the ‘‘ State Budgets, Unit Allocations, and Unit Emissions Rates ’’
TSD in the docket for this rule.

The proposed FIPs are designed to remove emissions from each upwind state that 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 existing units one time, before the Transport


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86 If a unit was allocated allowances but turned
out not to be a covered unit or turned out not to be required to hold allowances as of January 1, 2012, then the treatment of the allocation depends
on when the Administrator determines the unit is not subject to the trading program or to the allowance-holding requirement. For instance, if the allocation has not been recorded, the Administrator would not record it, and, if the allocation has been recorded and the Administrator has not completed the compliance determination process for the unit, allowances equal to the allocation would be deducted from the unit’s compliance account. Rule cap and trade programs commence ( see discussion of schedule, later). The allocations generally would bepermanent (with the exception of nonoperating units, discussed later) as base amounts and would not be updated. (Note that any unused new source set
aside 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 development 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 Emissions 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 program 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, or turned out not to be required to hold allowances to cover emissions, as of the first day of the control period in 2012, 86 or if the unit stops operating for three consecutive

years.

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; any unit listed in Appendix A whose allocation is subject to the requirement that the Administrator not
record the allocation or that the
Administrator deduct the amount of the allocation ( see previous discussion in footnote), 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 operation.

EPA believes it is important to have
a small new unit set-aside in each state to cover new units within the budget
that was set aside to address the state’s significant contribution and interference
with maintenance. To create new unit set-asides, EPA would 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 Emissions Rates ’’ TSD). In this way, new units could be
allocated some allowances for their emissions, which are part of the the
state’s contribution to downwind
nonattainment or interference with

maintenance.

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 operation
because the unit would have no actual
emissions data on which to base such an
allocation.

EPA proposes that, for the first control period for which the new unit wants an
allowance allocation from the new unit set aside (after the first year of operation), 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 units that requested 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.

For each control period, 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 that 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 not operating for three consecutive years, the allowances that
would otherwise have been allocated to that unit, starting in the seventh year after the first year of non-operation,
would be allocated to the new unit setaside for the state in which the retired unit is located. This approach would
allow the size of the new unit set-asides to 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 setasides after a unit had ceased operating for 3 consecutive years (see ‘‘ State Budgets, Unit Allocations, and Unit

Emissions Rates ’’ TSD). EPA requests
comment on the size of the new unit setasides.

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 in the seventh year after the first year of non-operation. All allowances
that would otherwise have been
allocated to the unit for that seventh year 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 units), and
reflects the fact that new unit emissions are included in 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).

EPA proposes to continue allocating allowances to non-operating unitsduring the 3 consecutive years of nonoperation plus an additional 3-year period to reduce the incentive for owners to keep units operating simply to avoid losing the allowance
allocations for those units. Other options that EPA considered include continuing to allocate allowances for an unlimited period of time, or


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immediately discontinuing allocations to such units upon the unit ceasing operation.

Continuing allocations to nonoperating units 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 least
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 operating for 3 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 allocating 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 title IV 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

Emissions Rates ’’ TSD. EPA proposes to include final allocations for existing units in the Appendix A for each proposed trading program in the final Transport 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 and 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 July 1, 2012 for control periods in 2015. Recording allowances several years in advance supports the 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 prior 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 finalized 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 finalized 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 referencing any necessary adjustments
of the new unit allocations.

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 that 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 allowances, 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
other alternative allocation methods. One is discussed here, but EPA recognizes that there are many ways that
allowances could be allocated. EPA is requesting comment on whether the alternative described here or any other approach 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 maintenance in each upwind state. EPA believes that 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. Under 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 comment on an alternative methodology that still links unit allowances directly to the way state budgets were developed (and thus, significant contribution was defined). In the alternative, all units within a state would be treated as a single group. The
allocation 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 with maintenance) based 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, this alternative method for distributing allowances would have the effect of distributing 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.

There are other approaches to allocation. For example, EPA could identify groups of units in each state that are capable of having similar emissions characteristics (e.g., grouped by size, fuel type, or age). 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) perhaps based on each group’s proportional share of the state budget as projected in the initial year of the program. After apportioning a state’s budget to the groups of units, under such an approach
EPA could 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 approach distributes each state’s significant
contribution and interference with
maintenance to individual sources in the state. By determining groups and then distributing allocations within the groups based on proportional shares, this approach would treat units within the categories equally ( i.e. , it would not treat a source that had acted early to control differently from one that had yet to take control action).


### 45312 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

EPA requests comment on the proposed allocation approach, the alternative approach, and on any other approaches that are consistent with the
Court decision. EPA asks that commenters present any such approaches in detail 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).

(3) Allowance Management System

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 NO X programs would remain separate trading programs maintained in EPA’s existing AMS. AMS would be used to track Transport Rule trading program SO 2 and NO X allowances held by covered sources, as well as such allowances held by other entities or individuals. Specifically,
AMS would track the allocation of all

SO 2 and NO X allowances, holdings of

SO 2 and NO X 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 NO X allowances for compliance purposes, and transfers of
allowances 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 emissions 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 allowances, 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 NO X emissions in accordance with 40 CFR part 75. Most 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 already 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, one ton of reported emissions from one source is 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 establishes 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 NO X emissions by all existing covered sources by January 1, 2012 for states covered for the daily and/or
annual PM 2.5 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 commercial 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 deadline. EPA believes that using only the 180-day deadline would ensure
that new units have sufficient time to complete installation and certification of monitoring systems without having to request extensions of time and would facilitate compliance by making the 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.

EPA also proposes to require designated representatives to submit quarterly reports that would include emissions and related data and proposes to establish a procedure for resubmission of quarterly reports where appropriate. Specifically, the proposed reporting provisions would include the same requirement to submit quarterly reports as the requirement in Part 75. In addition, the proposed provisions would include language that would make explicit a process that is implicit under, and has been in continuous use in, the Acid Rain, NO X Budget, and CAIR trading programs. The resubmission process would be as
follows. The Administrator could review and audit any quarterly report to determine whether the report met the monitoring, reporting, and recordkeeping requirements in the proposed rule and Part 75. The Administrator would provide notification to the designated representative stating whether any of these requirements was not met and specifying any corrections that the Administrator believed were necessary to make through resubmission of the report and a reasonable deadline for a response. The Administrator could provide reasonable extensions of such deadline. The designated representative would be required, within the deadline (including any extensions), to resubmit the report with the identified corrections, except to the extent the designated representative would submit information showing that a correction was not necessary because the report already met the monitoring, reporting, and recordkeeping requirements relevant to the correction. Any resubmission of a quarterly report would have to meet the requirements for quarterly report submission, except for
the deadline for initial submission of quarterly reports.

(5) Assurance Provisions

To ensure that 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 described 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, discussed in section IV. As described therein, 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 the 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


### 45313 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

any single year, the state’s emissions must not exceed the state budget with the variability limit allowed for any single year for that 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-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 that 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 covered 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 variability 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-year 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 Tables IV.F–1 through
IV.F–3 in section IV. The basis for the variability limits 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 exceeded 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
source 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 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 (regardless of whether 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 emissions during 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 state 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 where 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 variability limit—would necessarily 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: 84 percent for coal-fired units, 66 percent for gas-fired combined cycle units, and 15 percent for combustion turbines in
the NO X annual and SO 2 trading programs; and 89 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 and thus avoid attributing to each new unit a share of the state budget with variability reflecting the maximum amount of emissions possible for the unit in its first operating year, in the
case 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).


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87 U.S. Environmental Protection Agency (U.S. EPA). 2002. Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies. Washington, DC. These assurance provisions are above and beyond the 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 penalties, 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 emissions 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 this 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, even without assurance provisions, has succeeded in reducing emissions below allowance levels. The accumulated data, 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 variability limit. An example of a circumstance that might 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 state 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 to
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 the owner would be required to make an allowance
surrender of one allowance for each ton emitted over the owner’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 budgets plus the variability 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 FIPs.

(6) Penalties

All covered sources must hold an
allowance for each ton of SO 2 or NO X emitted and are subject to penalties ifthey fail to comply with this allowanceholding requirement.

Each source must hold in its compliance account in the AMS enough allowances issued for the respective annual trading program (SO 2 group 1,
SO 2 group 2, or NO X 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 excess 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 allowances
and emissions are for an ozone season.

EPA requests comment on the amount of allowances required for the automatic penalties.

c. 2012 and 2013 Transition Period

For the 2012–2013 transition period, EPA is proposing the State Budgets/ Limited Trading remedy without the previously-described assurance provisions (penalty provisions would remain 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 Transport Rule region. These state budgets would reflect the operation of all existing and planned
emission control devices. Under EPA’s proposed approach, for 2012 and 2013, intrastate 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. 87

Consequently, EPA believes that there is a high level of certainty that emissions reductions projected for


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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 believes 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 would 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 preparing 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 significant 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 and therefore likely increase compliance 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 variability 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 to 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 operations 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 as extreme weather or the loss of generating capacity for extended periods of time. e. How Emissions Cap and Trade Programs Have Worked Under Title IV,
the NO X SIP Call, and CAIR

Even absent assurance provisions, cap and trade programs have resulted in
broad-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 NO X 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 reductions.

Æ An emissions cap is established and the programs are phased in, with increasing stringency to lower

emissions.

• Allowance allocation.

Æ Authorizations to emit, i.e.

, allowances, are allocated to affected sources and are limited by each state’s trading budget.

• Allowance trading.

Æ Markets enable sources to trade
allowances.

• Flexible compliance.

Æ Sources have the flexibility to choose the most efficient way to comply including adding emission control technologies, updating control technologies, optimizing existing controls, switching fuels, and buying
allowances.

• Annual reconciliation.

Æ 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.

• Penalties and enforcement.

Æ There are automatic penalties and potentially discretionary civil penalties for program noncompliance.

• Stringent monitoring and reporting.

Æ Sources must use approved monitoring methods under EPA’s stringent monitoring requirements (40 CFR part 75) to monitor and report

emissions.

• Data transparency.

Æ 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 with 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 ( http://www.epagov/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 Program—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 electricgenerating units (including 1,055 coalfired 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 statutory 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 reflects 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 areas 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. PM 2.5 and ozone health-related
benefits estimate that PM 2.5 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.

See EPA’s docket for this rule and http://www.epagov/airmarkets/progress/

ARP

_ 4.html.


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88 U.S. 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.

89 Ge  ́ go, E., P.S. Porter, A. Gilliland, and S.T. Rao, 2007: Observation-Based Assessment of the Impact of Nitrogen Oxides Emissions Reductions on Ozone Air Quality over the Eastern United States. J. Appl. Meteor. Climatol., 46, 994–1008.

90 Godowitch, J.M., Hogfrefe, C., & Rao, S.T. 2008. Diagnostic analyses of a regional air quality model: Changes 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.

91 Godowitch, J.M., Gilliland, A.B., Draxler, R.R., and Rao, S.T. 2008. Modeling assessment of point

source NO X emission reductions on ozone air quality in the eastern United States. Atmospheric Environment, 42 (1), 87–100. 92 Ellerman, A. Denny. 2004. ‘‘ The U.S. SO 2 Capand-Trade Programme, ’’ Tradeable Permits: Policy Evaluation, Design and Reform, chapter 3, pp. 71–
97, OECD. 93 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.

94 Personal communication with Gary Hart, ICAPUnited, 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 Assessment of a Cap-and-Trade Program. ’’ Electricity Journal. Aug/Sept. 2007, Vol. 20, Issue 7. doi:10.1016/j.tej.2007.07.001.

95 Tietenberg, T.H. 2006. Emissions Trading Principles and Practice. Washington, DC. Published by Resources for the Future.

96 Ibid., p. 41.

97 Ibid., p. 73.

98 Ibid., pp. 70–71. NO X 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 emissions rate for the 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 projected 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 ozone NAAQS in 2004, 88 areas (85 percent) had ozone air quality better
than the level of the 1997 standard 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 by the NO X SIP Call rule. 88

Over the past several years a series of
studies 89 90 91 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 effective 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 reductions requirements under the NO X SIP Call and can use the CAIR NO X ozone season trading program to meet
these. See EPA’s docket for this rule for
more details on the results of the NO X Budget Trading Program, or see http:// www.epagov/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 ozone 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, until 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, the allowance
markets remained active. For a recent assessment on allowance markets, see http://www.epagov/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 some have suggested
that transaction 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 studies 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 92 of MIT, published in 2004. Ellerman suggests that, while no comprehensive study has been conducted on the subject, ‘‘ * * * the
creation of a standard unit of account in allowances and the lack of any review requirement for trading has avoided the very large transactions costs that limited * * * earlier experiments with emissions trading. ’’ Other studies (see Schennach, 2000 93 ) suggest transaction costs are about one percent of the allowance price. An industry expert, Gary Hart, 94 suggested that a typical fee charged by a brokerage firm is $0.50 for
each SO 2 allowance.

Tietenberg, in his book, Emissions Trading Principles and Practice, 95 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 word, ‘‘ 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 the market, finding buyers or sellers, negotiating and enforcing contracts for permit transfers, completing all the regulatory paperwork, and making and collecting payments. ’’ 96 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 streamlines monitoring and reporting. ’’ 97 He goes on to say, ‘‘ Price transparency (making prices public) can reduce the uncertainty associated with trading and facilitate negotiations about price and quantity. One good example is [the] public auctions held each spring for the Sulfur Allowance Program [ARP]. ’’ 98

Tietenberg contrasts EPA’s earlier credit-based trading programs in the


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99 Memo from ICF International to EPA Clean air Markets Division, September 17, 2008. Transaction Costs in Allowance Trading Markets.

100 Ibid. 101 Note that in cases where EPA has not fully identified the quantity of emissions that represent significant contribution or interference with maintenance, state budgets define the emissions that remain after the part that has been identified
is eliminated. 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 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 authorized 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 principle ways to ensure lower transaction costs.Over the last 15 years, EPA’s state-ofthe-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 public 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 accurately, 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, and 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 transaction 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 records 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 regulations 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). Allowances may be held in an allowance account ( i.e.

, banked) for use or trading in any future year in which the trading program
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 allowances 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 transparency 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. 99 In many instances, clients can negotiate fees even lower than market averages. Financial exchanges, such as the Chicago Climate Exchange and New York Mercantile Exchange, added SO 2 and NO X allowances to their list of
commodities. Prior to the vacatur of CAIR, transaction costs (broker fee as a percent of allowance price) were estimated at less than 0.2 percent for

SO 2 , less than 1.8 percent for seasonal

NO X , and less than 0.5 percent for
annual NO X
. 100 These transaction costs are low and not expected to affect program outcome.

In summary, EPA believes its cap and trade programs functioned efficiently and did not result in high transaction costs for several reasons. First, in 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 participating in the trading programs over the past 15 years that expressed 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 of 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, all available information
indicates that actual transactions costs are very low. For a list of some 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 Proposed FIPs Is Consistent With the Court’s Opinions

The proposed remedy discussed in this section effectuates the statutory 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. The proposed FIPs eliminate all
or the emissions that EPA has identified as significantly contributing to
downwind nonattainment or
interference 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 emissions 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. 101 State budgets represent EPA’s estimate of the remaining
emissions after elimination of significant contribution, but in actuality


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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, among other things, changing weather patterns, demand growth, or disruptions in electricity supply from other units 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 controls and taken all measures necessary 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 takes into account the inherent 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 variability of emissions across a larger region is not as large as the variability of emissions in a single state
for several reasons. Increased 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 emissions levels, are more likely to vary significantly within the region so that resulting emissions changes in different parts of the region are more 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 be offset by decreased demand
and emissions due to weather in another 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, the 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, the fact that the proposed use of state budgets with the variability limit may allow limited shifting of emissions between states is
not inconsistent with the Court’s holding that emissions reductions must

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 Proposing the State Budgets/Limited Trading Option

The FIPs that EPA is proposing use the State Budgets/Limited Trading remedy to eliminate all of 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-effective 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.

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, pollution 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 to 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 sections III.B and IX. The proposed remedy would offer the most expeditious approach practicable for compliance in 2012–2013, given the short time available for sources, states, 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 fuel 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 meantime, 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 limits 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. This approach in the proposed remedy, which is modeled in several ways after the approaches of the ARP and NBP programs, is likely to lead to virtually 100 percent compliance. The approach ensures that, as we see economic growth, future air quality is not compromised and states can depend on emissions reductions in meeting local air quality goals.

The limited interstate trading permitted 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 administering 82 new trading programs (with 82 new sets of allowances),


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conducting 82 annual auctions, concentrated allowance market power within individual states, and regional electricity reliability. In particular, the interstate trading component with assurance 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 than 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 with much more flexibility to ensure electric reliability in the event of future variability in electricity demand ( e.g. , due to weather or economic changes) or in the availability of specific individual electricity generation
facilities.

In addition, the proposed 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 proposed remedy in 2012. See section 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 costeffective 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 continue to operate as an integrated, interstate system able to provide electric reliability. Compared to the alternative options, EPA believes the State 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 of 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 throughout 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 provides added
assurance that emissions reductions now will occur on a state-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 upfront 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 together 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 requests 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 Limited Interstate Trading Options Evaluated

EPA considered a range of ways tocreate an interstate-trading-withlimitations option consistent with the direction provided by the Court. One option considered 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 considered 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. This is not EPA’s proposed option 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, 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 ‘‘ Other Remedy Options Evaluated ’’ TSD in the docket contains greater detail on the
deliberations undertaken to evaluate other options for this rulemaking.

i. Structure and Key Elements of Proposed Transport Rule Trading Program Rules for 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 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 trading programs ( i.e. , the Transport Rule NO X Annual trading program, Transport Rule NO X Ozone Season trading program, Transport Rule


### 45320 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 Ozone 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
Abbreviations

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 NO X , annual and ozone season), 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 in prior EPA-administered trading programs, in some cases with modifications to reflect the specific, proposed 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 the 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 units and sources, Transport Rule NO X Ozone Season units and sources, 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 instead 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 monitoring system ’’ is essentially the same as in prior trading programs, except for references to the proposed Transport Rule trading program rules.

Some definitions would be similar to those used in prior EPA-administered trading programs but with some substantive 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 minimize 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 assurance 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 definition of ‘‘ state ’’ ) differences in the specific states whose EGUs are covered by the respective Transport Rule 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 cogeneration units
and solid waste incineration units. The applicability provisions 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 ’’ exemption 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 allowanceholding requirements. However, an
owner would include each of these permanently retired units that it owns in determining whether and, if so, how many allowances 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 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 owner would
have to surrender allowances under the assurance provisions.

The exemption for a retired unit would begin on the day the unit is permanently retired. The unit’s designated representative ( i.e. , the person authorized by the owners and operators to 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 provisionswould not directly address any permitrelated matters concerning 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 the existing, applicable state and federal title V permit programs. Permitting is 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 presented 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 address designated representative requirements and emissions monitoring, reporting, and recordkeeping


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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
other sections that would set forth the procedures for determining compliance
with the emissions limitations and assurance provisions. These paragraphs would also explain that: 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 would each authorize
emission of one ton of emissions under the applicable Transport 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 CAA; 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

Court’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 be 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 program 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 owners 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 from any other requirements under the CAA, an approved SIP, or a federally enforceable permit.

(iv) §§ 96.407, 97.507, 97.607, and 97.707—Computation of Time

These sections would clarify how to
determine the deadlines referenced in the proposed 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-timeprovisions used in prior EPAadministered trading programs.

(v) §§ 97.408, 97.508, 97.608, 97.708 and Part 78—Administrative Appeal
Procedures

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 existing part 78, an ‘‘ interested person ’’ (in addition to the official representative of owners and operators or an allowance account involved in a matter) may petition for an administrative appeal of
a final decision of the Administrator. In order to expand the ‘‘ 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 cover 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 Board in other 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, 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 persons list.

In addition, § 78.3 would be revised to allow for petitions for administrative appeal of decisions of the Administrator under the proposed Transport Rule trading programs. Further, § 78.4 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 include 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 trading 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 I to Phase II) 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 Appendix 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 recorded for the non-operating unit. Because the proposed unit-by-unit
allocations are set forth in the ‘‘ State Budgets, Unit Allocations, and Unit

Emissions Rates ’’ TSD cited previously,


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the proposed Transport Rule trading program rules do not repeat these allocations in Appendix A to each rule. Instead, each Appendix A is reserved,and EPA proposes to include the unitby-unit allocations, for each Transport Rule trading program, in Appendix A to the respective final Transport Rule trading program rules.

With regard to new units (as well as units whose allocations are subject to the requirement that the Administrator
not record them or that the
Administrator deduct the amount of the
allocation 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, an 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)—for 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 itsproportionate share of the new unit setaside. 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 a 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.

If a unit that was not really a covered unit or a unit that was not subject to the allowance-holding requirement were allocated allowances, the proposed provisions set forth a process under
which the allocation would not be
recorded or the amount of 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 Representatives 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 procedures for 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 representative’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 patterned after the provisions concerning designated representatives 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 Transport 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 programs. 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 designated 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
source and covered 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 signatures of the designated representative and alternate. All submissions ( 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 complete certificate of representation, the
Administrator would establish a compliance account in the Allowance Management System for the source
involved.

In order to change the designated representative or alternate, a new certificate of representation would have 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 unavailable), additional flexibility would be provided 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, while 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 emissions limitations and assurance provisions, in an efficient and transparent manner. The Allowance Management System would also provide the allowance markets with a record of ownership of allowances, dates of allowance transfers, buyer and seller information, and the
serial numbers of allowances
transferred. Consistent with the approach in prior EPA-administered trading program, allowance price


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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: compliance 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 designated representative and
alternate for the source 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 managing 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 person or group for holding or trading allowances. However,
allowances 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 account representative; an identifying name for the account; the names of all persons 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 Transfers

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 the recordation deadline, e.g. , for 2015 in 2012. Recording these allowance allocations about 3 years in advance 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 representative 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 the 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

Limitations

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 allowance 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 their emissions 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 allocated 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 the
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 firstin, 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 control 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 unauthorized emissions and each day of the control


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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 explanation provided by the owners and operators for 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

Provisions

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 owner’s share 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, 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 program 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 of the control period) a legal, equitable, leasehold, or
contractual reservation or entitlement in the Transport Rule units at the source; and the percentage of each such person’s reservation or entitlement.

Third, by September 15, the Administrator would calculate, 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 results 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 a 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 would 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 settlement or an administrative appeal whose results were in turn appealed in a judicial proceeding resulting in such 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 revised 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 calculated 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 this potential risk would be significant enough that it 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 resulting from decisions in, or settlement of, litigation initiated soon after promulgation of the notice involved.


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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 allowance 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 alone—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 Through 97.428, 97.526 Through 97.528, 97.626 Through 97.628, and 97.726 Through 97.728—
Miscellaneous Provisions

These sections would allow banking
of the allowances issued in the Transport Rule trading programs, i.e.

, the retention of unused Transport Rule 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 cause 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 with 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 in 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 adjusted
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 clear, 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 essential to the success of the Transport Rule trading programs. This is because
consistent 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 to 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 with flexibility in achieving compliance. Moreover, given the variation 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 reportingrequirements under previous EPAadministered trading programs, e.g. , the
ARP and NO X Budget and CAIR trading

programs. Part 75 was originally developed for
the ARP and addressed SO 2 mass emissions and NO X emissions 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 NO X SIP Call, to address monitoring and reporting of

NO X 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 reference the applicable provisions in Part 75. Existing Transport Rule units would be required to install and certify monitoring systems by the beginning of the relevant Transport Rule trading program. New Transport Rule units have separate deadlines based 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 Part 75 through existing trading programs, continued use of previously certified monitoring systems would 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 the monitoring methodologies. These stringent requirements result in an accurate accounting of the mass emissions from each unit, and EPA provides prompt feedback if the monitoring system is not operating properly. In addition, when the monitoring system is not operating


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properly, standard substitute data procedures are applied and result in a
conservative estimate of emissions for the period involved. 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 containing 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 would contain the same requirements for submission to the Administrator of electronic, comprehensive quarterly reports as in Part 75. As discussed above, the reporting provisions would also include a process for resubmission of quarterly reports where appropriate.

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 eliminating 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 requests
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 , NO X annual, and NO X ozone season emissions from EGUs and create separate allowance trading programs within each state in the respectiveregions starting in 2012. The statespecific caps would ensure that all required reductions occur within the
state and thus would address the Court’s concerns about abating each individual 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. However, a source could only use, for compliance with this requirement, an allowance issued for
the state where the source was located. For purposes of obtaining allowances usable in compliance, sources within
each state could trade allowances amongst themselves, but not with
sources located in other states. Total
emissions in each state could not exceed that state’s budget and there would be no shifting of emissions to other states 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 sources in the state could use for compliance only allowances issued for the same state. Even a company that operates EGUs in multiple states would not be permitted to use for compliance for one
of its sources allowances issued to
another of its sources in a different state. In essence, this approach, if implemented, would result in 28 separate trading programs for NO X annual, 26 trading programs for NO X ozone season, and 28 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 responsible 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 Trading 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 State Budgets/Limited Trading remedy), limited year-to-year (temporal) emissions variability is allowed. EPA requests comment on this approach to providing for emissions variability. EPA also requests comment on whether assurance provisions based on variability limits should be included in this option.

b. How the Option Would Be Implemented

(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 detailed discussion on applicability.

(2) Allocation of Emissions Allowances

While the general approach for calculating allowance allocations would
be the same as described above for State Budgets/Limited Trading, EPA would
not distribute all of the allowances into the source accounts each period. The
distribution of allowances would be
modified because of the concentrated nature of numerous state power markets, which would be reflected in
the state allowance markets if all
allowances were distributed in each state based on factors reflecting generation in that state. The electric power sector tends to be highly concentrated, and, within a state, the majority of generation is often owned by a relatively small number of companies. This assessment of state electricity markets is supported by analysis using 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, Market
Concentration and Auction Size Technical Support Document). To address this potential issue concerning the allowance markets in many states, under this option some allowances
would be withheld from certain sources in each state that control a large share of fossil-fueled power generation and


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would be made available for companies with a small share of generation in the

state.

The reason for including this provision is that the dominant power generation companies in each state would likely receive a large share of the
allocated allowances and as a result might be able to exert control over allowance prices in the state’s allowance market. This market power and potential for allowance price manipulation could pose a threat to the transparency and liquidity of allowancemarkets and put small owners of fossilfuel fired generation at a disadvantage regarding their compliance costs unless the owners were given sufficient access to allowances other than through direct purchase from the state’s dominant companies. Some of these owners of a small share of generation might already face higher control costs, higher transaction costs, and less flexibility regarding compliance options.

Moreover, the use of allowance market power to manipulate prices could have wider impacts on electricity markets as a whole, electricity prices, and electricity 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 would 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 be 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 alternative 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 nonoperating units above for State Budgets/ Limited Trading in section V.D.4 would remain the same for this option. (3) Auction of Emissions Allowances

The use of an annual allowance auction would 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 dominant companies.
This means that EPA would hold a total of 82 auctions every year to separately

auction SO 2 and NO X ozone season and

NO X annual allowances in each of the 82 intrastate trading programs. The auction format would be single-round, uniform-price, 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 sources 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. 3302.

EPA would use auctions to address market power concerns rather than other options it considered. The Agency considered using a different allowance
allocation 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
state. 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 potential 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 severalyears of experience running singleround, sealed-bid auctions for Title IV

SO 2 allowances. Other formats
considered such as multi-round
auctions are believed to be more complicated for participants to understand and more complex to administer and do not discourage
collusion.

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 nomore than 10 percent of the total fossilfuel 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 that 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 several units, have more flexibility, receive a significant share of allowances, and face lower control and transaction costs. EPA is 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 option would be to divide companies in each state into three groups, instead of


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just two. The first group would be the companies that own no more than 10 percent of the total fossil-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 fossilfuel 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
comments on this variation on the alternative option and other ways to address potential market power problems and on this alternative option.

(4) Allowance Management System

The allowance management system for the State Budgets/Intrastate Trading option would be consistent with the allowance management system for the State Budgets/Limited Trading 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.

(5) Monitoring and Reporting

Monitoring and reporting provisions would require complete, quality-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 detailed 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 28 SO 2 or 28
NO X 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 Trading remedy option. However, because sources in 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 temporal variability due to banking). For this reason, EPA does not believe that any other penalties or assurance provisions (such as the assurance provisions used in the State Budgets/ Limited Trading 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 Consistent With the Court’s Opinions

The state 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
that emissions from sources that 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 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
emissions 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 each affected state’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 contributing to nonattainment or
interference with maintenance.

The number of allowances in each state budget would be distributed or made available (through an auction or otherwise) 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 season) 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 state. 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 Issues

EPA requests comments about whether the State Budgets/Intrastate Trading alternative option could have adverse consequences for electric reliability. The grid regions, and the movement of electricity within each grid 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 sources 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 states, 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 year, 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 Trading remedy. The other remedy options 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 integrated 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.


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102 Joskow, Paul and Edward Kahn, 2002. A Quantitative Analysis of Pricing Behavior In California’s Wholesale Electricity Market During
Summer 2000: The Final Word.

103 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.

104 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. e. How Smaller Market Trading Programs Have 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. In addition, states range in size and number of potential program participants making each state’s circumstances unique and more challenging for EPA to monitor.

(1) Texas Mass Emissions Cap and Trade (MECT)

EPA has approved a NO X cap and trade program as part of an ozone
attainment SIP for the Houston Galveston Brazoria (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 capacity 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 allows 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 year 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. Current 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 the 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. Allowance 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) Regional Clean 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 were 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 in 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 program. Every facility then complied using valid credits of either cycle, but banking of allowances for use in a later period was not allowed.

RECLAIM Trading Credits (RTC) prices for NO X 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. Prices of RTCs during the California energy crisis during 2000 and 2001 averaged in the $50,000 per ton range. 102 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 theCalifornia crisis, RTCs had been overallocated, 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 were partly caused by the high demand for credits resulting directly from the manipulation of the power market by generators. 103

The operation of the RECLAIM market also contributed to the high prices in the overall power markets. During this period, generators would pay excessively high prices for RTCs in order to raise the price of southern California generation needed to meet demand in the California Independent System Operator (CAISO). Subsequently, generation with high RTC
costs in the RECLAIM area would be used to set the electricity 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. 104 Since that time, significant changes have been adopted to improve the program.

According to the audit report for the 2007 compliance period, total aggregate

NO X emissions were below total allocations by 21 percent and total aggregate SOX emissions were below total allocations by 13 percent. Since January 2008, NO X RTCs prices have been declining and have not exceeded $15,000 per ton.


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f. Why This Is Not the Preferred 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 actually 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 issues 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 on which EPA is requesting comment is the direct control option described in this section. EPA is considering the relative merits of this option and requests
comment on whether a direct control 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 emissions
rate limits to individual sources.
Emissions limits would take the form of input-based emissions rate limits (lb/ mmBtu).

EPA requests comments on the direct control remedy summarized later and the approach for determining emissions rate limits, which is described in greater
detail in the ‘‘ State Budgets, Unit Allocations, and Unit Emissions Rates ’’ TSD in the docket for this rulemaking. 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) discussedpreviously, which both use flexible capand-trade approaches, a direct control remedy would directly regulate
individual sources. Under this direct control remedy alternative, each owner of EGUs would be required to meet specified average emissions rate limits covering all of its EGUs in each covered
state. In a state covered for the 24-hour
and/or annual PM 2.5 NAAQS, the direct control remedy option would require each company within the state to meet specified EGU annual emissions rate
limits for SO 2 and NO X . In a state covered for the 8-hour ozone NAAQS, this remedy would require each company within the state to meet specified EGU ozone season emissions
rate limits for NO X . EPA would set emissions rates on a unit-by-unit basis in all covered states ( see approach to determine emissions rate limits, later).

While emissions 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 eachstate to meet the specified within-thestate rate limits. Company-level averagerates would be calculated as companylevel total emissions divided by company-level total heat input in eachstate. Analogously, allowable companylevel 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 emissions 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 budget 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 the 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 presents 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 the company’s 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 covered state do not exceed the state’s budget with variability limit. They are
described later. EPA also believes the penalty provisions described later are sufficient to ensure that these caps
would not be exceeded.

To implement this remedy option,
EPA would determine unit-level
emissions rate limits for SO 2 , NO X 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 of each pollutant from these units would sum to each state’s emissions budget for the pollutant 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 each state. However, this 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 Implemented

(1) Approach To Determine Emissions

Rate Limits

To implement this remedy option,
EPA would determine unit-level
emissions rate limits for SO 2 , NO X annual, and NO X ozone season, for
covered EGUs in the covered states.


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Emissions rate limits would be set 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 the state budgets. In a state covered for purposes of the PM 2.5 NAAQS, EPA would determine SO 2 and

NO X annual emissions 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 emissions rate limits for each
covered EGU.

Emissions rate limits for Phase I (2012 and 2013) . State budgets were derived
from the lower of available 2007–2009 quarterly emissions or IPM base case projections for 2012, at the state level. Analogous to state budget calculation,
EPA would base the Phase I annual
emissions 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 first, 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, if available, and projections or source-specific judgments
otherwise.

For units where EPA is aware that

SO 2 or NO X controls will be installed by
2012 and such controls were not reflected in the unit’s reported emissions rate as determined previously ( i.e. , the control was not in operation during the period of time on which emissions limits were based), EPA
would determine the Phase I emissions rate limit as the historic rate adjusted (reduced) to reflect operation of the planned control equipment at an emissions rate consistent with operation of that equipment. Emissions rate limits
would be determined based on the assumption that units operate all existing SO 2 and NO X 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 , NO X , and/or a complete ozone
season of NO X 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 emissions rate limits based on modeling projections. Based on the analysis conducted for this proposed rule, EPA would use modeling projections to determine SO 2 rates for 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 based 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 account 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 fourth 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 could impact the ability of EPA to require the reductions as quickly as under other remedy approaches.

EPA is also taking comment on an alternative approach for setting
emissions rate limits for those units which did not report a first, second, third, and fourth quarter of SO 2 , NO X , 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, toensure that all units in a broadlydefined group could achieve their rate limits, it would be necessary to either establish limits that are fairly weak so that the poorest-performing units could meet the requirements ( ‘‘ lowestcommon-denominator ’’ effect), or, design more stringent requirements but include provisions for exceptions to the requirements. At this time, EPA believesusing IPM projections and sourcespecific 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 emissions rates for certain EGUs that EPA projects would install FGD in modeling of the proposed remedy option (at less than $2000 per ton); for such units EPA would
determine emissions rate limits at rates consistent with FGD operation. For other covered units, Phase II emissions
rate limits would be the same as Phase I limits. Again, emissions rate limits
would be determined based on the assumption that units operate all existing SO 2 and NO X 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 emissions rate limits for covered new units would be set equal to the permit rates for these units.

EPA has calculated specific emissions rate limits for each existing unit that
would be covered under this direct control remedy option. These unit-level emissions rate limits appear in a table
entitled ‘‘ Phase I and Phase II unit-level
emissions 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 provided in the TSD. EPA is requesting comment on this approach for determining the emissions 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 previously 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 Provisions

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


### 45332 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

exceed the state budget with 1-year variability limit in any year (or ozone season, as applicable). Additionally, on a 3-year rolling 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 section 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 limit in 2012 and 2013, and not a 2-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 emissions 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- 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 limit, 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. Those assurance provisions 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 program requirement to surrender one allowance for every ton
emitted.

In the direct control alternative, however, allowances are not allocated to units therefore an allowance surrender requirement is not feasible. Instead, for this alternative, a company with 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, would 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 direct 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 combination 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/Limited Trading remedy, the direct control program does not put a price on emitting SO 2 or NO X so does not provide that incentive to reduce

emissions. Sources can increase generation, while meeting the emissions rate limits, and increase their emissions. For 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 2012.

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 emissions rate limits for SO 2 and/or NO X emission for all of its EGUs.
For the annual SO 2 or NO X control programs, if a company were to exceed the applicable company-wide annual average rate limit, the company would be in violation of the CAA and subject to discretionary civil penalties.

The excess emissions of the owner’s
EGUs would be calculated as the EGUs ’’ actual annual average emissions rate minus the applicable annual average emissions 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 CAASection 113 is $25,000 (inflationadjusted 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 , NO X 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.

c. How the Direct Control Remedy Is Consistent With the Court’s Opinions

The direct control remedy option would implement the section 110(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 emissions rate limits, with company-wide within state averaging. Emissions 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 budgets without the variability limits. A company could average the emissions at its units withineach state to meet specified within-thestate rate limits. This approach would directly limit emissions from EGUs in each covered state, providing assurance
that emissions reductions would occur
within each state consistent with the mandate of section 110(a)(2)(D)(i)(I).


### 45333 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

Because individual EGUs would be required to meet specific emissions rate limits (with within-state company-wide averaging), this option would ensure that required controls and measures are installed and implemented within the state. The fact that emissions, after implementation of all controls required to meet the emissions rate limits, may vary based on the amount of generation
in each state 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 state and
thus the baseline emissions from that
state. Because baseline emissions are variable, emissions after the elimination of all significant 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 state’s EGU emissions would be permitted to exceed the state budget with variability 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.

d. Electric Reliability Issues

The risk to electric 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 emissions 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 emissions 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 follow. 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 concerns 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 costs 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 on which EPA is taking comment 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 direct control approach on which EPA is taking comment, 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 with a small number of units at a disadvantage compared to an owner with a larger number of units
within a state. EPA seeks comment on
this issue. A direct control program based on emissions rate limits does not cap annual emissions; if there is growth infossil generation within a state, a ratebased approach alone could allow
emissions increases. In the direct control approach on 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 reductions 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 should be considered qualitatively, even if they cannot be 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 base 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 IPM Documentation.



### T ABLE 

### V.E–1—P ROJECTED 

### I NCREMENTAL 

### C OSTS 

### D UE TO 

### T RANSPORT 

### R ULE 

### R EMEDIES 

### C OMPARED TO 

### B ASELINE 

### W ITHOUT 

### T RANSPORT 

### R ULE 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


### 45334 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

1. State Budgets/Limited Trading

The proposed remedy of State Budgets/Limited Trading was modeled with regional emissions caps beginning in 2012 and state-specific emissions limits beginning in 2014. The statespecific 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.



### T ABLE 

### V.E–2—P ROJECTED 

### SO 2 AND 

### NO X 

### E LECTRIC 

### G ENERATING 

### U NIT 

### E MISSIONS 

### R EDUCTIONS IN 

### C OVERED 

### S TATES 

### W ITH THE 

### T RANSPORT 

### R ULE 

### C OMPARED TO 

### B ASELINE 

### W ITHOUT 

### T RANSPORT 

### R ULE 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

2. State Budgets/Intrastate Trading

Though based 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 2 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.



### T ABLE 

### V.E–3—P ROJECTED 

### SO 2 AND 

### NO X 

### E LECTRIC 

### G ENERATING 

### U NIT 

### E MISSIONS 

### R EDUCTIONS IN 

### C OVERED 

### S TATES 

### W ITH THE 

### I NTRASTATE 

### T RADING 

### A LTERNATIVE 

### R EMEDY 

### C OMPARED TO 

### B ASELINE 

### W ITHOUT 

### T RANSPORT 

### R ULE 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 3.2 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 emissions
rate limits commensurate with those used in the derivation of state budgets (see sections 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 banking 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 with fuel switching.



### T ABLE 

### V.E–4—P ROJECTED 

### SO 2 AND 

### NO X 

### E LECTRIC 

### G ENERATING 

### U NIT 

### E MISSIONS 

### R EDUCTIONS IN 

### C OVERED 

### S TATES



### W ITH THE 

### D IRECT 

### C ONTROL 

### A LTERNATIVE 

### R EMEDY 

### C OMPARED TO 

### B ASELINE 

### W ITHOUT 

### T RANSPORT 

### R ULE 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 3.8 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


### 45335 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

105 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 NO X requirements nor in the ozone season NO X requirement. Modeled units in DC include 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. 4. State-Level Emissions Projections

Tables V.E–5, V.E–6, and V.E–7 show projected emissions at the state level
from all EGUs in 2014.



### T ABLE 

### V.E–5—P ROJECTED 

### S TATE



### - LEVEL 105 

### SO 2 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS IN 

### 2014

[Tons]

Base case State budgets/ limited trading State budgets/ intrastate trading Direct control

Alabama ........................................................................................... 322,362 172,430 162,103 172,4 30
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 13 5,366 Georgia ............................................................................................ 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 10 6,569
Kansas ............................................................................................. 65,125 51,248 52,501 53,275 Kentucky .......................................................................................... 739,595 123,837 128,318 123,8 33
Louisiana .......................................................................................... 94,866 94,933 92,647 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
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 22 8,514 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 58,3 30 West Virginia .................................................................................... 496,307 127,646 147,580 127,64 6
Wisconsin ......................................................................................... 117,397 85,933 87,328 83,709



### T ABLE 

### V.E–6—P ROJECTED 

### S TATE 

### -L EVEL 

### A NNUAL 

### NO X 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS 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
Florida .............................................................................................. 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 52,06 9
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 .......................................................................................... 53,029 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


### 45336 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### V.E–6—P ROJECTED 

### S TATE 

### -L EVEL 

### A NNUAL 

### NO X 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS IN 

### 2014—
Continued

[Tons]

Base case State budgets/ limited trading State budgets/ intrastate trading Direct control

South Carolina ................................................................................. 47,742 34,735 33,781 34,616
Tennessee ....................................................................................... 68,914 28,212 26,874 28,873 Virginia ............................................................................................. 37,485 35,805 35,745 37,00 4 West Virginia .................................................................................... 100,095 48,180 48,987 50,555
Wisconsin ......................................................................................... 54,515 41,875 42,498 42,450



### T ABLE 

### V.E–7—P ROJECTED 

### S TATE 

### -L EVEL 

### O ZONE 

### -S EASON 

### NO X 

### E MISSIONS 

### F ROM 

### E LECTRIC 

### G ENERATING 

### U NITS 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 2,669 2,671 2,613
District of Columbia ......................................................................... 391 397 397 398
Florida .............................................................................................. 94,686 62,221 62,037 48,17 0 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 42,78 9
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 16,09 3
West Virginia .................................................................................... 24,339 20,249 21,466 21,500

F. Transition From the CAIR Cap and Trade Programs To Proposed Programs

This proposed Transport Rule would replace the CAIR rule and its associated trading programs. 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.

1. Sunsetting of CAIR, CAIR SIPs, and

CAIR FIPs

The CAIR, 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 order 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 requirements
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 out any of the functions established for the
Administrator 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 that 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 2012 control period for every one


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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. , 2012 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 and
CAIR FIPs would 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 subject 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 periods —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 sources would be out of compliance with the requirement to hold allowances covering 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 the 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, state 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 civil penalties under CAA Section 113. Each ton of excess emissions, and each day in the control period involved ( 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 periods (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 previouslydescribed, proposed revisions to §§ 51.123, 51.124, 52.35, and 52.36, certain 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 approving 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 transitioning 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 orworkshops, web-based references, oneon-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 no state action would be required to accomplish this sunsetting.EPA proposes to revise each statespecific 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 proposed 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


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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 Texas 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 would include Connecticut, Kansas, Massachusetts, Minnesota, and Nebraska and would not include Mississippi and Texas. ( See also the discussion in section IV.D. regarding the possibility that the states to which this rule would apply could expand.)

Consequently, 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
SIPs. 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 trading programs. In contrast, under CAIR, states could elect to allow boilers, combustion turbines, and other combustion devices to opt into the CAIR trading programs under opt-in provisions specified by EPA, and a number of states adopted these opt-in provisions. 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 state 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

NO X 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 generating units (serving generators with nameplate capacity of 15 through 25 MWe), and generally the CAIR NO X ozone season budgets in these states
were increased to account for these additional sources. In contrast, the proposed Transport Rule NO X ozone season 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 which 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 under 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 NO X ozone season trading program. In fact, their current emissions rates are nearly identical 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 states expand applicability to include them. EPA is taking comment on this approach.

4. Early Reduction Provisions

Substantial emissions reductions have
occurred as a result of the CAIR programs. These reductions 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
2009. This bank is the result of
emissions 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 in 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 banks and encouraging continued emission
control. EPA is concerned that the approach would have significant legal risk for two reasons. First, the Court is likely to view the approach as imposing a significant burden on the use of Title
IV allowances and therefore as modifying the authorization provided by such allowances. Second, the Court is likely to view the approach as not related to, much less necessary for, implementation of the section 110(a)(2)(D)(i)(I) mandate to eliminate significant contribution and interference with maintenance. EPA chose instead, under the proposed Transport Rule, to distribute Transport Rule SO 2 allowances in a manner directly linked
to its calculation of each state’s significant contribution and interference
with maintenance and not to use Title IV allowances as a basis for distributing the new Transport Rule allowances. EPA is confident that the approach


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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 distribution 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 for 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. NO X 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 budgets under the proposed Transport
Rule NO X ozone season program for 2012), and the CAIR NO X annual bank would contain about 720,000 allowances (which would equal nearly 50 percent of the total of the state budgets under the proposed Transport
Rule NO X annual 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 banks have not yet been modeled. However, EPA is concerned about the potential impacts of theseapproaches. On one hand, allowing pre2012 CAIR NO X allowances and CAIR

NO X ozone season allowances to be used in the proposed Transport Rule

NO X programs, and thereby ensuring
that the allowances would continue to have some market value in the future, would 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 emissions 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 possibleapproaches for handling banked pre2012 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 that some parties may view this approach as having the effect of allowing sources that were advantaged by the development of state budgets using fuel adjustment factors—the use of which was reversed by the Court in North
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. These concerns may be mitigated somewhat by the fact that even though the methodology used to divide the regional budget into state budgets used fuel factors, states had the flexibility to allocate allowances however they wished. EPA takes
comment on the extent to which states have allocated differently and the extent to which this may mitigate concerns about allowing the use of banked CAIR

NO X allowances in the Transport Rule
annual NO X and ozone season 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 allowances 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 programs 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
emissions reductions 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 Transport 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 not be
feasible because EPA cannot determinein advance in which states banked pre2012 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 tonot allow the use of any banked pre2012 CAIR allowances in the Transport
Rule NO X 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 possibleapproaches for handling banked pre2012 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 for 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 monitoring 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

NO X ozone season requirements but

NO X and SO 2 annual requirements under the proposed Transport Rule; or CAIR states subject to CAIR NO X annual
and ozone season and SO 2 requirements but only to NO X ozone season requirements under the proposed Transport Rule. These exceptions could arise, in part, because under Part 75 some units ( i.e. , non-Acid Rain units)
that are in NO X ozone season, 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 NO X yearround 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, South 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 Rule.


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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.

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 natural 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 part 75. Kansas, Minnesota, and Nebraska 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 need 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 Part 75 that would need to begin to do so. Most of these units are simple-cycle
combustion 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 are already monitoring and reporting under 40 CFR part 60, subpart Da, which requires an SO 2 , NO X and CO2/ O2 (diluent) CEMS. These boilers would only have to add a flow monitor and upgrade 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 have not been covered by part 75 monitoring and reporting in the past would likely have less than one year to install, certify, and operate the required monitoring 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 and 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 affect any Acid Rain Program requirements. Any Title IV sources that 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
the 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 NO X 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 into 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 complied with the Transport Rule, emissions 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 nearly zero. Acid Rain sources will still be required to comply with Title IV requirements, including the requirement to hold 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 states 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 in the absence of the Transport Rule. There is more discussion of this effect

in section IV.D.

2. NO X SIP Call Interactions

States affected by both the NO X SIP Call and any final Transport Rule will be required to comply with the requirements of both rules. 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 all NO X SIP Call states. The NO X SIP Call states
used the NO X Budget Trading Program (NBP) to comply with the NO X SIP Call requirements for EGUs serving a generator with a nameplate capacity 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. To address

NO X SIP Call requirements, fourteen

NO X SIP Call states chose to expand the

CAIR NO X ozone season applicability to
include all NBP-affected units. EPA has analyzed the effect of allowing states to expand their CAIR NO X ozone season applicability and consequently their

CAIR NO X 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
units did not reduce their NO X emissions or their NO X emissions rates
as a result of their inclusion in the CAIR

NO X ozone season program. If EPA were to allow them to be part of the Transport
Rule NO X Ozone Season Program, and
if states were allowed to increase the Transport Rule NO X Ozone Season Budgets by the amounts allowed under the NBP and CAIR for these units, 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


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106 The 2005 findings of failure to submit related to states’ obligations 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). maintenance would be to require the budget increase to be much less than
allowed under the NBP and CAIR. For example, the units’ 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 applicability of the Transport Rule.

Therefore, the NBP states would need
to achieve their NO X SIP Call emissions reductions another way in order to continue to comply with the NO X SIP Call. If EPA promulgates a final rule that does not allow the expansion of the Transport Rule to NBP units, any state that allowed these units 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 emissions 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 state 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, 2009 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 to ensure 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 stakeholder-related materials may be
found in the EPA docket for the transport rule (EPA–HQ–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 has 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:

• Analysis and baselines.

• 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 calls 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 receptors.

• 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. State Implementation Plan
Submissions

A. Section 110(a)(2)(D)(i) SIPs for the
1997 Ozone and PM 2.5 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

PM 2.5 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). Also 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) 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 satisfy 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) obligation. 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 section 110(a)(2)(D)(i)(I) 106 remain in force regardless of whether a state covered by the CAIR submitted


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107 Part 70 governs approved state Title V programs, and part 71 governs the federal Title V

program. 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 PM 2.5 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 interfering with maintenance under this proposed rule and whose 110(a)(2)(D)(i)(I) SIPs with respect to the
1997 ozone and PM 2.5 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 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 PM 2.5 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 PM 2.5 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 call, 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, in today’s notice EPA is proposing to
finalize the FIP for Kansas for ozone only if the state fails 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 PM 2.5 NAAQS
With respect to the 2006 24-hour

PM 2.5 NAAQS, EPA has issued a separate Federal Register notice finding
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 SIPs for the
2006 24-hour PM 2.5 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 PM 2.5 NAAQS only if EPA finds the previously submitted SIP incomplete or disapproves the SIP submission. Alternatively, if any of
these states withdraws its 2006 24-hour

PM 2.5 SIP submittal, EPA plans to issue a separate notice of finding for such

states.

C. Transport Rule SIPs

EPA also notes that, by promulgating these Transport Rule FIPs, EPA would in no way affect the right of states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. In order to replace the FIP in a state, the state’s SIP must provide adequate provisions to prohibit NO X and SO 2 emissions that contribute significantly to
nonattainment or interfere with
maintenance in another state or states. The Transport Rule FIPs would be in place in each covered state until a state’s SIP was submitted and approved by EPA to replace a FIP.

For each upwind state covered by the proposed Transport Rule, EPA proposes state-specific emissions reductions requirements with respect to one or more of three air quality standards—the
1997 annual PM 2.5 NAAQS, the 2006 24-
hour PM 2.5 NAAQS, and the 1997 ozone NAAQS. In CAIR, EPA allowed the states to replace the CAIR FIP with SIPs and provided substantial flexibility. Again EPA wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues through a SIP should they choose to do so. The EPA’s intent is to provide states with substantial flexibility in implementing these emissions reductions requirements. EPA will
allow a state to submit a SIP for the ozone requirements only, for the PM 2.5 requirements only, or for both the ozone
and the PM 2.5 requirements. The specific quantity of emissions reductions necessary for a state’s SIP
would be determined based on the state emissions budgets provided in the final transport rule. ( See Tables IV.E–1 for proposed SO 2 and annual NO X budgets, and IV.E–2 for proposed ozone season

NO X budgets, in section IV.E).

In the states for which EPA is proposing to require reductions with respect to both the 24-hour PM 2.5 NAAQS and the annual PM 2.5 NAAQS,
there is no case where the annual
standard drives the reduction requirements deeper than would the 24- hour standard alone. Thus, emissions reduction requirements for a SIP to address significant contribution and
interference with maintenance with respect to the 24-hour PM 2.5 NAAQS
would be based on the SO 2 and NO X emissions budgets in Table IV.E–1. For such a state, a SIP that addresses the requirements with respect to the 24-
hour PM 2.5 NAAQS would also by definition address the requirements with respect to the annual PM 2.5 NAAQS.

EPA is taking comment on all aspects of how a state could replace the Transport Rule FIP with a SIP and on what the SIP approval criteria should
be.

VIII. Permitting

A. 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. 107 Title V requires that sources meeting certain criteria have permits meeting the requirements 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 (definition 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. For example, requirements under the proposed FIPs concerning designated representatives, 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.


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108 A permit 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). The Title V permits program includes, 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 program 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, allowances could be traded (or allocated, held, or 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
modifications ‘‘ 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 applicable 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 applications (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 reporting 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 proposed 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 excepted 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 Title 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).

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 reopening 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)). 108 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 that would identify the applicable requirements under the trading program and thereby ensure 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 content template would also reduce the burden on sources in obtaining, on permitting authorities in issuing, and on EPA in reviewing, permits or permit revisions.

B. New Source Review

EPA recognizes that pollution control projects, including pollution control projects constructed to comply with the proposed rule, have the potential to trigger new source review (NSR) permitting.

On December 20, 2005, the EPA agreed to reconsider one specific aspect of the CAIR. In that notice, EPA granted reconsideration and sought comment on the potential impact of a judicial opinion, New York v. EPA , 413 F.3d 3 (D.C. Cir. 2005). This decision vacated the pollution control project exclusion in EPA’s NSR regulations. (The
exclusion allowed for certain environmentally beneficial pollution control projects to be excluded from certain NSR requirements.) For this reconsideration, EPA conducted an analysis which showed that the court decision did not impact the CAIR analyses. The EPA believes this analysis, which remains current and relevant for all pollutants except for greenhouse gas (GHG), shows that New Source Review (NSR) requirements would not significantly impact the
construction of controls that are installed to comply with the proposed transport rule. Details of this analysis can be found in a Technical Support
document which is available on EPA’s
Web site at: http://epa.gov/cair/pdfs/ 0053–2263.pdf.

Because GHG was not considered by
EPA to be a ‘‘ pollutant ’’ , let alone a

‘‘ regulated pollutant, ’’ at the time of CAIR, GHG was not addressed in the previous analysis. GHG requirements related to the component of new source review concerning the Prevention of Significant Deterioration ( ‘‘ PSD ’’ ) program have recently been addressed

in EPA’s ‘‘ Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs, ’’ 75 FR 17004 (April 2, 2010), and

‘‘ Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, ’’ 75 FR (June 3, 2010) ( ‘‘ Tailoring
Rule ’’ ). Generally, as discussed in those actions, once the PSD requirements for GHG take effect on January 2, 2011, major stationary sources will be required to address GHG emissions as part of the PSD program if these sources emit GHG in amounts that equal or


### 45344 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

109 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.

110 As described in the AQMTSD, the eastern U.S.

was modeled at a horizontal resolution of 12 x 12 km. The remainder of the U.S. was modeled at a

resolution of 36 x 36 km.

111 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. exceed the thresholds in the Tailoring Rule. Once the PSD requirements take effect, major sources that undergo a modification, including the addition of pollution control equipment, will trigger PSD requirements for their emissions of GHG if such emissions increase by at least 75,000 tons per year of CO 2 equivalent. EPA believes it is very unlikely that pollution control projects
would cause GHG increases that would exceed the 75,000 tons per year
threshold.

Consistent with EPA’s previous analysis and EPA’s conclusions for GHG, EPA does not believe that there are significant impacts from NSR for any pollution control projects resulting from the proposed rule such as low-NO X burners, SO 2 scrubbers, or SCR. EPA requests comment on this issue.

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

PM 2.5 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 ‘‘ State Budgets/ Limited Trading ’’ remedy proposed in this rule, as described in section V,
above.

Implementation of this rule will very substantially lower the extent of
nonattainment and maintenance problems for the annual and 24-hour

PM 2.5 NAAQS and 8-hour ozone 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) for the proposed ‘‘ State Budgets/Limited Trading ’’ remedy. There will be significant benefits that are not quantified. 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 PM 2.5 cobenefits is largely driven by the concentration-response function for premature mortality, we examined alternate relationships between PM 2.5 and premature mortality supplied by experts. Higher and lower co-benefits estimates are plausible, but most of the expert-based estimates fall between
these two estimates above. 109 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 emissions 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 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 legal 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.

Following 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 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 Title 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 PM 2.5 and Ozone of the Proposed SO 2 and NO X 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 NO X emissions reductions on annual average PM 2.5 , 24-hour PM 2.5 , and 8-hour ozone concentrations. In brief, we ran the CAMx model for the meteorological conditions in the year of 2005 for the eastern U.S. modeling domain. 110 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 PM 2.5 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 NO X are provided
in Table V.E–2 in section V.E. The emissions by state 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 PM 2.5 , daily PM 2.5 , and ozone at each monitoring site in the East for which projections were made are provided 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 PM 2.5 , daily PM 2.5 , and ozone are provided in Table IX–1. 111 The average and peak reductions in annual PM 2.5 , daily PM 2.5 , and ozone predicted at 2012
nonattainment and/or maintenance sites
due to the emissions reductions


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112 ‘‘ Nonattainment ’’ is used to denote sites that are projected to have both nonattainment and maintenance problems. between 2012 and the 2014 remedy are provided in Table IX–2.



### T ABLE 

### IX–1—P ROJECTED 

### R EDUCTION IN 

### N ONATTAINMENT AND 

### / OR 

### M AINTENANCE 

### P ROBLEMS FOR 

### PM 2.5 AND 

### O ZONE IN

THE 

### E ASTERN 

### U.S.

Ambient (2003–2007) 2012 base

case 2014 base

case 2014 proposed remedy Percent reduction: 2012 base case vs. 2014 remedy

(percent) Percent reduction: 2014 base case vs. 2014 remedy

(percent)

Annual PM 2.5 Nonattainment Sites 112

..... 102 32 15 1 97 93
Annual PM 2.5 Maintenance-Only Sites .... 21 16 7 1 94 86 Daily PM 2.5 Nonattainment Sites ............. 151 92 54 17 82 69 Daily PM 2.5 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



### T ABLE 

### IX–2—A VERAGE AND 

### P EAK 

### R EDUCTION IN 

### A NNUAL 

### PM 2.5 

### , D AILY 

### PM 2.5 

### , AND 

### O ZONE FOR 

### S ITES 

### T HAT 

### A RE 

### P ROJECTED 

### T O 

### H AVE 

### N ONATTAINMENT AND 

### / OR 

### M AINTENANCE 

### P ROBLEMS IN THE 

### 2012 B ASE 

### C ASE

Average reduction: 2012 base case to 2014 remedy Peak reduction: 2012 base case to 2014 remedy

Annual PM 2.5 Nonattainment Sites ......................................................... 2.8 μ g/m 3 ....................................... 3.9 μ g/m 3

Annual PM 2.5 Maintenance-Only Sites .................................................... 2.6 μ g/m 3 ....................................... 4.2 μ g/m 3 Daily PM 2.5 Nonattainment Sites ............................................................. 5.8 μ g/m 3 ....................................... 15.3 μ g/m 3 Daily PM 2.5 Maintenance-Only Sites ....................................................... 5.1 μ g/m 3 ....................................... 13.5 μ g/m 3 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 significant reductions
in the extent of nonattainment and maintenance problems for annual PM 2.5 , daily PM 2.5 , 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 other existing control programs. Specifically, the 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 PM 2.5 in 2014 with the emissions reductions expected from this proposal. As indicated in Table IX–2, the average
reduction in annual PM 2.5 across the 32

2012 nonattainment sites is 1.9 μ g/m 3 and the peak reduction at an individual

nonattainment site is 3.2 μ g/m 3

. Comparable reductions are projected at
annual PM 2.5 maintenance-only sites.

For 24-hour PM 2.5 , we project that the
number of nonattainment sites will be reduced by 82 percent and the number of maintenance-only sites by 71 percent in 2014 compared to the 2012 base case. The average reduction in 24-hour PM 2.5 across the 92 2012 nonattainment sites

is 5.8 μ g/m 3 and the peak reduction at an individual nonattainment site is 15.3

μ g/m 3 . Comparable reductions are projected at 24-hour PM 2.5 maintenanceonly sites.

The emissions reductions in this 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 PM 2.5 standard. On average for these 28 sites, the predicted
amount of PM 2.5 reduction 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 NO X emissions
reductions which will result from today’s proposal will greatly reduce the
extent of PM 2.5 nonattainment and maintenance problems by 2014 and beyond. As described previously, these emissions reductions are expected to substantially reduce the number of

PM 2.5 nonattainment and/or
maintenance sites in the East and make
attainment easier for those counties that remain nonattainment by substantially lowering PM 2.5 concentrations in
residual nonattainment sites. The emissions reductions will also help those locations that may have maintenance problems.

Based on the 2012 base air quality modeling for ozone, 27 sites in the East are projected to be nonattainment or have problems maintaining the 1997 ozone standard. The initial phase of

summer NO X 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 2012 base case. We expect that the number of nonattainment sites will be reduced by 36 percent and the number of maintenance-only sites by 69 percent in 2014 compared to the 2012 base case. For the 12 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 indicates that by 2014 the initial phase of summer

NO X emissions reductions in this proposal will lower ozone concentrations in the East and help bring areas closer to attainment for the 8-hour ozone NAAQS.


### 45346 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

113 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. 114 Laden et al. , 2006. ‘‘ Reduction in Fine Particulate Air Pollution and Mortality. ’’ American Journal of Respiratory and Critical Care Medicine.

173:667–672. 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 PM 2.5 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 the RIA. For context, it is important to note that the magnitude of the PM 2.5 benefits is largely driven by the concentration response function for premature mortality. Experts have advised EPA to consider a variety of assumptions, including estimates based both on empirical (epidemiological) studies and judgments elicited from scientific experts, to characterize the uncertainty in the relationship between PM 2.5 concentrations and premature mortality. For this proposed rule we cite two key empirical studies, one based on the American Cancer Society cohort study 113 and the other based on the extended Six Cities cohort study. 114

Table IX–3 presents the primary
estimates of reduced incidence of PM 2.5 and ozone-related health effects in 2014 for the proposed and alternative remedies. In 2014, we estimate that PMrelated 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, 11,000 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

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 shortterm mortality in 95 U.S. 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 variability in health-related damages from coal-fired 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.



### T ABLE 

### IX–3—E STIMATED 

### A NNUAL 

### R EDUCTIONS IN 

### I NCIDENCE OF 

### H EALTH 

### E FFECTS A

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 attacks (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) **Ozone-related endpoints** Premature mortality

Bell et al. (2004) (all ages) ................................................................................................................................. 50 (17–84) Levy et al. (2005) (all ages) ............................................................................................................................... 230 (160–300) Hospital 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)


### 45347 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IX–3—E STIMATED 

### A NNUAL 

### R EDUCTIONS IN 

### I NCIDENCE OF 

### H EALTH 

### E FFECTS A 

### —Continued

Health effect Proposed remedy

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 quantifying the visibility benefits of the
alternate remedies. The 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 Transport Rule 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-related damages resulting from 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 risk 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 categories that could not be quantified or monetized in our benefit estimates are provided in
Table IX–6.



### T ABLE 

### IX–4—E STIMATED 

### A NNUAL 

### M ONETARY 

### V ALUE OF 

### R EDUCTIONS IN 

### I NCIDENCE OF 

### H EALTH AND 

### W ELFARE 

### E FFECTS
(Billions Of 2006$) A

Health effect Pollutant Proposed remedy

Premature mortality (Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates)

3% discount rate ......................................................................................... PM 2.5 & O 3

....................................... $110 ($8.8–$340)

7% discount rate ......................................................................................... PM 2.5 & O 3

....................................... $100 ($7.9–$300)

Premature mortality (Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates)

3% discount rate ......................................................................................... PM 2.5 & O 3

....................................... $280 ($25–$820)

7% discount rate ......................................................................................... PM 2.5 & O 3

....................................... $260 ($22–$310)

Chronic bronchitis ........................................................................................ PM 2.5

................................................ $4.3 $0.2–$20)

Non-fatal heart attacks.

3% discount rate ......................................................................................... PM 2.5

................................................ $2.5 ($0.4–$6)

7% discount rate ......................................................................................... PM 2.5

................................................ $2.4 ($0.4–$5.9) Hospital admissions—respiratory ................................................................ PM 2.5 & O 3

....................................... $0.06 ($0.03–$0.1) Hospital admissions—cardiovascular .......................................................... PM 2.5

................................................ $0.2 ($0.1–$0.3) Emergency room visits for asthma ............................................................. PM 2.5 & O 3 ....................................... $0.005 ($0.002–$0.008)

Acute bronchitis ........................................................................................... PM 2.5 ................................................ $0.009 (

¥ $0.0004–$0.03) Lower respiratory symptoms ....................................................................... PM 2.5 ................................................ $0.005 ($0.002–$0.009) Upper respiratory symptoms ....................................................................... PM 2.5 ................................................ $0.006 ($0.001–$0.014)

Asthma exacerbation ................................................................................... PM 2.5 ................................................ $0.012 ($0.001–$0.046) Lost work days ............................................................................................ PM 2.5

................................................ $0.2 ($0.19–$0.24) School loss days ......................................................................................... ..................................................... $0.01 ($0.004–$0.013) Minor restricted-activity days ....................................................................... PM 2.5 & O 3

....................................... $0.64 ($0.34–$0.97) Recreational visibility, Class I areas ........................................................... PM 2.5

................................................ $3.6

Total benefits based on Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates

3% discount rate ......................................................................................... PM 2.5 & O 3

....................................... $120 ($10–$360)

7% discount rate ......................................................................................... PM 2.5 & 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 ......................................................................................... PM 2.5 & O 3

....................................... $290 ($26–$840)

7% discount rate ......................................................................................... PM 2.5 & O 3

....................................... $270 ($24–$760)

A Estimates rounded to two significant figures.


### 45348 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

E. How do the benefits compare to the costs of this proposed rule?

The estimated annual private costs to implement the emission reduction requirements of the proposed rule for the Transport 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 in 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 percent discount rate. Thus, the net benefit (social benefits minus social 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 percent and 7 percent discount rates) in 2014. Implementation of the rule is expected to provide society with a substantial net gain in social welfare based on economic efficiency criteria.

The annualized regional cost of the proposed rule, as quantified here, is
EPA’s best assessment of the cost of implementing 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 federal courts. The direct 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 closely as possible, the 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 XII.B., Paperwork Reduction Act). However, there may exist certain costs that EPA has not quantified in these estimates. These costs may include costs of transitioning to this rule, such as the costs associated
with the retirement of smaller or less efficient EGUs, employment shifts as
workers are retrained at the same company or re-employed elsewhere in the economy, and certain relatively small permitting costs associated with Title 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 lower 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 entire economy. These impacts are summarized in section X of this preamble and in the RIA for this proposed rule.



### T ABLE 

### IX–5—S UMMARY OF 

### A NNUAL 

### B ENEFITS 

### , C OSTS



### , AND 

### N ET 

### B ENEFITS OF THE 

### T RANSPORT 

### R ULE IN 

### 2014

[Billions of 2006 dollars]

Description Proposed remedy

Social costs: 3 percent discount rate ........................................................................................................ .................................... $2.0. 7 percent discount rate ........................................................................................................ .................................... $2.2.

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 three 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 Rule region.

c As this table indicates, total benefits are driven primarily by PM 2.5 -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 United 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 IX–6. We represent the value of unquantified benefits and disbenefits with a ‘‘ B. ’’

e Valuation assumes discounting 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 percent 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.


### 45349 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

115 In this analysis, we adjust the VSL to account for a different currency year (2006$) and to account for income growth to 2014. After applying these adjustments to the $6.3 million value, the VSL is $8.5 million.

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 geographic coverage), and uncertainties in the underlying
scientific and economic studies used 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 economic 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 the 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 pollutant concentrations including the shape of the C–R function, the size of the effect estimates, and the relative toxicity of the many components of the PM mixture;

• Uncertainties in exposure estimation; and

• Uncertainties associated with the effect of potential 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 approach 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 $6.3 million (2000$). 115 The benefits estimates generated for this rule are 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:

(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 lowest air quality levels modeled in this analysis. Thus, the estimates include health benefits from reducing fine particles in areas with varied
concentrations of PM 2.5 , including both regions that are in attainment with fine particle standard and those that 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 peer-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 benefit-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 are the unquantified and unmonetized benefits of the Transport
Rule emissions reductions?

Important benefits beyond the human health and welfare benefits resulting
from reductions in ambient levels of

PM 2.5 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
reductions. These benefits are listed in Table IX–6. Some of the more important examples 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 in emissions required by the Transport Rule: Reduced acid deposition, reduced eutrophication of estuaries, and reduced vegetation impairment from ozone.

1. What are the benefits of reduced deposition of sulfur and nitrogen to aquatic, forest, and coastal ecosystems?

Atmospheric deposition of sulfur and nitrogen, often referred to as acid rain,
occurs when emissions of SO 2 and NO X 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 borders. Together these emissions are 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 ability [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 water 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


### 45350 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

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 watersheds that have
few alkaline minerals and shallow soils. Conversely, 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 (particularly, the Adirondack and Catskill Mountains, portions of NewEngland, and streams in the midAppalachian highlands) and southeastern streams. This regulatory action will decrease acid deposition in the transport region and is likely to have positive effects 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, accelerating 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 levels 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 climatic stresses such as droughts and cold temperatures. They can also influence the sensitivity of plants to other stresses, including insect pests and disease (Joslin et al. , 1992), leading to increased mortality of canopy trees.

Both coniferous and deciduous 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 limiting nutrient in coastal 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 deposition 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 19 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 estuaries is associated with a range of adverse ecological effects. The conceptual framework 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 degrades 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, and they serve as the breeding grounds and interim habitat for several migratory species.

This rule 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 Methylation 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 evidence 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

environments.

2. Ozone Vegetation Effects

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 pollutantwith the greatest potential for regionalscale 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 ground-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 particular plants from ground-level


### 45351 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

ozone, scientists have developed ozoneexposure/tree-response functions by exposing tree seedlings to different ozone levels and measuring reductions in growth as ‘‘ biomass loss. ’’ Typically, seedlings are used because they 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 fitness 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 ozonesensitive 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 effectson seedlings compound to affect longterm 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 ornamentals (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.) and a variety of ornamental 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 discussed 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 limiting 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 percentage 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 potential but unquantifiable benefits may also arise
from 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 surfaces. 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 radiation reaching the earth, but EPA believes that we areunable to quantify any net climaterelated 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.



### T ABLE 

### IX–6—U NQUANTIFIED AND 

### N ON 

### -M ONETIZED 

### E FFECTS OF THE 

### T RANSPORT 

### R ULE

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 soiling. 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

. NO 2 : health ....................................................... Respiratory hospital admissions. Respiratory emergency department visits.

Asthma exacerbation. Acute respiratory symptoms. Premature mortality. Pulmonary function.
NO 2 : 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.


### 45352 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

T ABLE 

### IX–6—U NQUANTIFIED AND 

### N ON 

### -M ONETIZED 

### E FFECTS OF THE 

### T RANSPORT 

### R ULE 

### —Continued

Pollutant/effect Endpoint

Other ecosystem services and existence values for currently healthy ecosystems.
SO 2 : health ....................................................... Respiratory hospital admissions. Asthma emergency room visits.

Asthma exacerbation. Acute respiratory symptoms. Premature mortality. Pulmonary function.
SO 2 : welfare ..................................................... Commercial fishing and forestry from acidic deposition. Recreation in terrestrial and aquatic ecosystems 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 health 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 incremental 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 emissions 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 costs do not consider transfer payments (such as taxes) 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 costs 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.

Overall, the economic 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 electricity. For more information on electricity price changes that result from this proposal, please refer to section XII.H (Statement of Energy Effects) later in this preamble.

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 pollution control policies for SO 2 and NO X throughout the contiguous United States for the entire power system.

Documentation 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. Documentation 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 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. 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).

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 associated compliance costs. By reducing electricity demand, energy efficiency avoids emissions of all pollutants associated with electricity generation, including emissions of NO X 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 costeffectiveness of energy efficiency investments by internalizing
environmental costs associated with these pollutants, EPA is interested in considering additional means by which energy efficiency can be encouraged through 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 reduce the demand for electricity from EGUs in affected states. Energy


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116 U.S. EPA. 2004. Guidance on State Implementation Plan (SIP) Credits for Emission Reductions From Electric-Sector Energy Efficiency and Renewable Energy Measures. August. http:// www.epa.gov/ttn/oarpg/t1/memoranda/

ereseerem

_ gd.pdf. 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 cost-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 investment in costeffective 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 in EGU 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 of 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 rule, 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 NO X 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 generationcosts, this will improve the relative costeffectiveness 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 energy efficiency into air regulatory programs?

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 NO X Budget Trading program, and the Regional Greenhouse 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 arerealized) as are the emissions of noncapped pollutants from affected EGUs.
In addition to these allowance-based programs, EPA has also established, through Guidance, 116 a means for recognizing the emissions benefits of energy efficiency in SIPs and has approved their use in individual state plans.

B. Incorporating End-Use Energy Efficiency Into the 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 Could Be Used To Incorporate Energy Efficiency Into Allowance Based Programs

As discussed previously, allowancebased programs (such as the proposed State 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 developing 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 emissions reductions requirements of the proposed rule are implemented through proposed FIPs. This means, among other things, that
EPA allocates the emission 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 developing 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 and III.B.3, EPA anticipates further revisions to the

PM 2.5 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 reductions 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 efficiency 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,


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1993), this action is an ‘‘ economically significant regulatory action ’’ because it is likely to have an annual effect on the economy of $100 million. 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. In addition, EPA prepared a Regulatory Impact Analysis (RIA) of the potential costs and benefits associated
with this action.

When estimating the PM 2.5 - and
ozone-related human health benefits and compliance costs in Table 1 below, EPA applied methods and assumptions
consistent with the state-of-the-science for human health impact assessment, economics and air quality analysis. EPA applied its best professional judgment in performing this analysis and believes that these estimates provide a reasonable indication of the expected
benefits and costs to the nation of the preferred and alternate Transport Rule remedies considered by the Agency. The Regulatory Impacts Analysis (RIA)
available in the docket describes in detail the empirical basis for EPA’s assumptions and characterizes the various sources of uncertainties affecting the estimates below.

When characterizing uncertainty in the PM-mortality relationship, EPA has historically presented a sensitivity analysis applying alternate assumed
thresholds in the PM concentrationresponse relationship. In its synthesis of the current state of the PM science, EPA’s 2009 Integrated Science Assessment (ISA) for Particulate Matter concluded that a no-threshold log-linearmodel most adequately portrays the PMmortality concentration-response relationship. In the RIA accompanying this rule, rather than segmenting out impacts predicted to be associated levels above and below a ‘bright line’ threshold, EPA includes a ‘‘ lowestmeasured-level (LML) ’’ that illustrates the increasing uncertainty that characterizes impacts attributed to
levels of PM 2.5 below the LML for each study. Figure 5–19 shows the distribution of avoided PM mortality impacts predicted relative to the baseline ( i.e. pre-Transport Rule) PM 2.5 levels experienced by the population receiving the PM 2.5 mortality benefit in 2014 (Figure 5–19). This figure also shows the lowest air quality levels measured in each of the two primary epidemiological studies EPA uses to quantify PM-related mortality. This
information allows readers to determine the portion of PM-related mortality benefits occurring above or below the LML of each study; in general, our
confidence in the size of the estimated
reduction PM 2.5 -related premature mortality decreases in areas where
annual mean PM 2.5 levels are further
below the LML in the two epidemiological studies. In this analysis, we see that about 80% of the estimated benefits accrue among populations exposed to annual mean

PM 2.5 levels above 10ug/m3 (the LML in the Six Cities study) and 97% of the
estimated benefits are associated with PM levels above 7.5 mg/m3 (the LML in the American Cancer Society study used for this analysis). While the LML analysis provides some insight into the level of uncertainty in the estimated PM mortality benefits, EPA does not view
the LML as a threshold and continues to quantify PM-related mortality impacts using a full range of modeled air quality

concentrations.

Table XII.A–1 shows the results of the cost and benefits analysis for the proposed and alternate remedies.



### T ABLE 

### XII.A–1—S UMMARY OF 

### A NNUAL 

### B ENEFITS 

### , C OSTS



### , AND 

### N ET 

### B ENEFITS OF 

### V ERSIONS OF THE 

### P ROPOSED 

### R EMEDY 

### O PTION IN 

### 2014 a

[Billions of 2006$]

Description Preferred remedy-State budgets/ limited trading Direct control Intrastate trading

Social costs b 3% discount rate ..................... $2.03 ............................................. $2.68 ................................... .......... $2.49. 7% discount rate ..................... $2.23 ............................................. $2.91 ................................... .......... $2.70.

Health-related benefits c,d 3% discount rate ..................... $118 to $288 + B .......................... $117 to $286 + B .......................... $113 to $276 + B. 7% discount rate ..................... $108 to $260 + B .......................... $108 to $262 + B .......................... $104 to $252 + B. Net benefits (benefits-costs) 3% discount rate ..................... $116 to $286 ................................ $115 to $283 ................................ $110 to $273. 7% discount rate ..................... $105 to $258 ................................ $105 to $259 ................................ $101 to $249.

**Notes:** (a) All estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for the year 2014. For notational purposes, unquantified benefits are indicated with a ‘‘ B ’’ to represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits that we were able to quantify. A listing of health and welfare effects is provided in RIA Table 1–6. Estimates here are subject to uncertainties discussed further in the body of the document. (b) The social costs are the loss of household utility as measured in Hicksian equivalent variation. (c) Thereduction in premature mortalities account for over 90% of total monetized benefits. Benefit estimates are national. Valuation assumes discounting over the SAB-recommended 20-year segmented lag structure described in Chapter 5. Results reflect 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000; OMB, 2003). The estimate of social benefits also includes CO 2 -related benefits calculated using the social cost of carbon, discussed further in chapter 5. Benefits are shown as a range fro m Pope et al . (2002) to Laden et al. (2006). Monetized benefits do not include unquantified benefits, such as other health effects, reduced sulfurdeposition or visibility. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle type. (d) Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all unquantified benefits and disbenefits. Potential benefit categories that have not been quantified and monetized are listed in RIA Table 1–4.

B. Paperwork Reduction Act

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 information 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


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will decide which units and what records or processes should be inspected. 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 requirements are specifically 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 Information.

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 necessary 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 conduct 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, 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 Regulatory 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 that 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 assessing 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. For the electric power generation industry, the
small business size standard is an ultimate parent entity defined as having a total electric output of 4 million megawatt-hours (MW-hr) or less in the previous fiscal year.

(2) A small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population 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.



### T ABLE 

### XII.C–1—P OTENTIALLY 

### R EGULATED 

### C ATEGORIES AND 

### E NTITIES a

Category NAICS Code b Examples of potentially regulated entities

Industry ................................................................. 221112 Fossil fuel-fired electric utility steam generating units.
Federal Government ............................................ c 221112 Fossil fuel-fired electric utility steam generating units owned by the federal government.
State/Local ........................................................... c 221112 Fossil fuel-fired electric utility steam generating units owned by municipalities. Tribal Government ............................................... 921150 Fossil fuel-fired electric utility steam generating units 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 classified 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 entities. This
certification is based on the economic impact of this proposed action to 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 percent 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 a result of this rule ( e.g. , install control equipment or switch fuels). Their increased 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 the
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 concluded 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 Regulatory Impact Analysis for this proposed rule. Finally, although EPA believes that the proposed rule would not have a significant economic impact on a


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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.

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 federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on state, 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 state, local, and tribal governments, in the aggregate, or the private sector in any one year. Accordingly, EPA has prepared 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 alternatives. In today’s action, EPA has included three remedy options that it 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 with the final rule an explanation why that alternative was not adopted.

EPA examined the potential economicimpacts on state and municipalityowned entities associated with 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, of 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, 27 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 these government entities can pass on their costs of compliance 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 potentially 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 affect small governments, including tribal 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 Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. Consistent 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 $100 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 state and local governments may also be impacted. The requirements in this action do not distinguish EGUs based 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 contains 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 state or local 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 state and local
officials.

F. Executive Order 13175: Consultation
and Coordination With Indian Tribal

Governments

This action does not have tribal implications, 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 responsibilities between the federal 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 Risks

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 potential to influence the regulation. 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 shall 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


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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 the Administrator 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, distribution, 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 2014. 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 nationally by less than 2.5 percent in 2012 and 1.5 percent in 2014. This is generally 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 2014as a result of higher demand for lowersulfur coals. The EPA also projects that natural gas prices will increase by less than 1.7 percent in 2012 and 0.5 percent in 2014 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 delivered 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 considerable 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 SO 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 electrical system. For more 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 ’’ ), Public Law 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 decides 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 costeffective for the regulated 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 forth 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 precluding 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 justice. 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, disproportionately high
and adverse human health or environmental effects of their programs,policies, and activities on minority, lowincome, and Tribal populations in the
United States.

1. Consideration of Environmental Justice Issues in the Rule Development

Process

In the rulemaking process, EPA considers 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 communities 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 others, people with asthma, people with heart disease, and people living in ozone or fine particle (PM 2.5 ) nonattainment areas. This rule also has the potential to affect the cost structure of the utility industry and could lead to regional shifts in electricity 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 information on air quality changes and the resulting 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 docket No. EPA–HQ–OAR–2009–0491 and from the main EPA Web page for the rule http:// www.epagov/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 controlling


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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 altered 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 otherwise alter their operations and had successfully begun reducing their
emissions. The court decision has led to significant uncertainty among affected
sources as to what emissions reductions will be required and among states and communities as to what air quality benefits will be achieved. By proposing this aggressive replacement rule that meets the legal requirements of the CAA as interpreted by the Court in the North
Carolina decision promptly, EPA is both maximizing the likelihood that the goals 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
emissions reductions achieved under
CAIR would be lost.

It is important to note that CAA section 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 PM 2.5 in communities. 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.

This proposed rule is one of a group of regulatory actions that EPA will take over the next several years to respond to statutory and judicial mandates that will reduce exposure to ozone and PM 2.5 , as well as to other pollutants, from power plants and other sources. To the extent that EPA has the legal authority to do so while fulfilling its obligations under the CAA and other relevant statutes, we 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). The primary actions are outlined below and presented in
more detail in section III.E of this preamble.

Beyond this action and any additional efforts undertaken in response to 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 emissions of air toxics, including mercury, and particles from coal- and oil-fired power plants; new National Ambient Air Quality Standards (NAAQS) for ozone, PM 2.5 , sulfur dioxide, and nitrogen oxides; potentially one or more additional rules eliminating interstate transport of emissions that contribute significantly
to nonattainment and maintenance areas
for the new ozone and PM 2.5 NAAQS as necessary; 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 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 Best Available Control Technology for their GHGs. Finally, EPA will pursue energy efficiency 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 lowering the costs of realizing those improvements.

Together, these rules and actions will have substantial and long-term effects on both the U.S. power industry and on communities currently breathing dirty air. Therefore, we anticipate significant interest in 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 justice 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 from the rules.

Emissions reductions. This proposed rule will reduce exposure to PM 2.5 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 thesepollutants that affect the mostcontaminated areas ( i.e. areas that are not meeting the 1997 and 2006 ozone
and PM 2.5 National Ambient Air Quality Standards (NAAQS)). This rule separately identifies both nonattainment
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 emissions 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 PM 2.5 concentrations in
both nonattainment and maintenance
areas identified in this rule are theresult of both local emissions and longrange 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 option for this
rule would use a limited emissions trading mechanism among power plants to achieve significant emissions reductions in states covered by the rule. EPA recognizes that many environmental justice communities
have voiced concerns about emissions trading and any resulting potential for any emissions increases in any location.


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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

PM 2.5 or ozone nonattainment or maintenance areas. EPA’s proposed mechanism for achieving these emissions reductions is to use a tightly constrained trading program that requires a strict emission ceiling in each state while allowing a limited ability to
shift emissions between facilities or states. This approach ensures that emissions in each state that significantly
contribute to downwind nonattainment or maintenance areas are controlled, while allowing power companies to adjust generation based on fluctuations 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 above the state’s allocated level must be offset by
emissions reductions from another state in the region below that state’s budget or by using extra ‘‘ banked ’’ allowances from earlier years. All sources must hold enough allowances to cover their emissions; therefore, if they emit more than their allocation they must buy
allowances from another source that
emitted less than its allocation. PM 2.5 and ozone pollution from power plants have both local and regional components: Part of the pollution in a given location—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
reductions 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 emissions rate for each facility is reduced but each facility could emit more by increasing 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 emissions 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 this action, by limiting the amount of interstate trading possible and by requiring any emissions above
the level of the allocations to be offset by emission decreases elsewhere in the region, the proposed remedy options
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 percent) lower in 2014 than they were in 2005 (which is the year that the Clean Air Interstate 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 emissions are greater in the control case 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 μ g/m 3 threshold for
annual PM 2.5 . 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 PM 2.5 NAAQS in downwind areas. EPA’s authority under § 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, such 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 be 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 result 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 PM 2.5 and 2006 PM 2.5 NAAQS. Table IX–1 lists the changes in
number of nonattainment sites. Most of
these sites are 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 in 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 emissions 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 emissions 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 concentrations 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


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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 the transport region are also predicted to see reductions in air concentrations, even though emissions increase in some of
these states. This is because concentrations of fine particles in most locations are composed of both local emissions and those transported over
hundreds of miles and emissions reductions far away can cause significant improvements in local air quality.

The modeling suggests also that there may be some small increases in PM 2.5 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 nature 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
reduce emissions in the areas not covered by this rule.

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 encompassing 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 required to make significant
reductions in NO X beginning in 2003
and these emissions 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 atmospheric chemistry reactions taking place among chemical constituents of air 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 concentrations 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 emissions reductions that might be causing extremely localized ozone increases are certainly causing larger, more widespread 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 PM 2.5 and that the federal government and the states can and do use many different legal authorities to limit exposure to ozone.

Health benefits. This rule reduces
concentrations of PM 2.5 and ozone pollution, exposure to which can cause, or contribute to, adverse health effects including premature mortality and many types of heart and lung diseasesthat affect many minority and lowincome individuals, and Tribal

communities. PM 2.5 and ozone are particularly (but not exclusively) harmful to children, the elderly, and people with 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 health 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 PMrelated 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 (for respiratory and cardiovascular disease combined), 10 million fewer days of restricted activity due to respiratory 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 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 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 benefit-per-ton estimation approach and found they would provide
similar benefits.

It should be noted that, as discussed in the RIA for this action, there are other
benefits to the emissions 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 Participation

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


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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 2009 EPA-Health and Human
Services White House Stakeholder Briefing entitled ‘‘ The Public Health Benefits of Energy Reform ’’ in which EPA discussed our intention 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 effects of these efforts in Indian country. These were not opportunities for stakeholders to comment on the specifics of this proposal, as they took place prior 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 regulated 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 smooth 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 environmental 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 that 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 resulting improvements in health. EPA also recognizes that there is the potential for a number of communities or individuals outside the region covered by this rule to experience slightly worse air quality as an indirect result of emissions 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.

List of Subjects

40 CFR Part 51

Administrative practice and procedure, Air pollution control, Intergovernmental relations, Nitrogen oxides, Ozone, Particulate matter, Regional haze, Reporting and recordkeeping requirements, Sulfur
dioxide.

40 CFR Part 52

Administrative practice and procedure, Air pollution control, Intergovernmental relations, Nitrogen oxides, Ozone, Particulate matter, Regional haze, Reporting and recordkeeping requirements, Sulfur
dioxide.

40 CFR Parts 72

Acid rain, Administrative practice and procedure, Air pollution control, Electric utilities, Intergovernmental relations, Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur
dioxide.

40 CFR Part 78

Acid rain, Administrative practice and procedure, Air pollution control, Electric utilities, Intergovernmental relations, Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur
dioxide.

40 CFR Part 97

Administrative practice and procedure, Air pollution control, Electric utilities, Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur dioxide. Dated: July 6, 2010.
Lisa P. Jackson,

Administrator.

For the reasons set forth in the preamble, parts 51, 52, 72, 78, and 97 of chapter I of title 40 of the Code of Federal Regulations are proposed to be
amended as follows:

**PART 51—[AMENDED]**

1. The authority citation for Part 51
continues to read as follows:

Authority: 23 U.S.C. 101; 42 U.S.C. 7401– 7671q.

**§ 51.121 [Amended]**

2. Section 51.121 is amended by revising paragraph (r)(2) by removing
the words ‘‘ § 51.123(bb) ’’ and adding, in their place, the words ‘‘ § 51.123(bb) with regard to an ozone season that occurs before January 1, 2012 ’’

.
**§ 51.123 [Amended]**

3. Section 51.123 is amended by adding a new paragraph (ff) to read as
follows:

**§ 51.123 Findings and requirements for submission of State implementation plan**  **revisions relating to emissions of oxides of nitrogen pursuant to the Clean Air Interstate** 

**Rule.**

* * * * *

(ff) Notwithstanding any provisions of paragraphs (a) through (ee) of this section, subparts AA through II and AAA through III of part 96 of this chapter, subparts AA through II and AAAA through IIII of part 97 of this chapter, and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011, the
Administrator:

(i) Rescinds the determination in paragraph (a) of this section that the States identified in paragraph (c) of this
section must submit a SIP revision with respect to the fine particles (PM 2.5 ) NAAQS and the 8-hour ozone NAAQS meeting the requirements of paragraphs (b) through (ee) of this section; and

(ii) Will not carry out any of the
functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 96 of this chapter, subparts AA through II and AAAA through IIII of part 97 of this chapter, or in any emissions trading program provisions in a State’s SIP approved under this section; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.


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**§ 51.124 [Amended]**

4. Section 51.124 is amended by adding a new paragraph (s) to read as
follows:

**§ 51.124 Findings and requirements for submission of State implementation plan**  **revisions relating to emissions of sulfur dioxide pursuant to the Clean Air Interstate** 

**Rule.**

* * * * *

(s) Notwithstanding any provisions of paragraphs (a) through (r) of this section, subparts AAA through III of part 96 of this chapter, subparts AAA through III of part 97 of this chapter, and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011, the
Administrator:

(i) Rescinds the determination in paragraph (a) of this section that the States identified in paragraph (c) of this
section must submit a SIP revision with respect to the fine particles (PM 2.5 ) NAAQS meeting the requirements of paragraphs (b) through (r) of this section; and

(ii) Will not carry out any of the
functions set forth for the Administrator in subparts AAA through III of part 96 of this chapter, subparts AAA through III of part 97 of this chapter, or in any emissions trading program in a State’s SIP approved under this section; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**§ 51.125 [Reserved]**

5. Section 51.125 is removed and
reserved.

**PART 52—[AMENDED]**

6. The authority citation for Part 52
continues to read as follows:

Authority: 42 U.S.C. 7401, et seq.

**Subpart A—General Provisions**

**§ 52.35 [Amended]**

7. Section 52.35 is amended by adding a new paragraph (f) to read as
follows:

**§ 52.35 What are the requirements of the Federal Implementation Plans (FIPs) for the**  **Clean Air Interstate Rule (CAIR) relating to emissions of nitrogen oxides?** 

* * * * *

(f) Notwithstanding any provisions of paragraphs (a) through (d) of this section, subparts AA through II and AAAA through IIII of part 97 of this chapter, and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011, (i) The provisions in paragraphs (a) through (d) of this section relating to

NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

**§ 52.36 [Amended]**

8. Section 52.36 is amended by adding a new paragraph (e) to read as
follows:

**§ 52.36 What are the requirements of the Federal Implementation Plans (FIPs) for the**  **Clean Air Interstate Rule (CAIR) relating to**

**emissions of sulfur dioxide?**

* * * * *

(e) Notwithstanding any provisions of paragraphs (a) through (c) of this section, subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraphs (a) through (e) of this section relating to

SO 2 emissions shall not be applicable;
and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

9. Subpart A is amended by adding §§ 52.37 and 52.38 to read as follows:

**§ 52.37 What are the requirements of the Federal Implementation Plans (FIPs) under**  **the Transport Rule (TR) relating to emissions of nitrogen oxides?** 

(a)(1) The TR NO X Annual Trading Program provisions of part 97 of this chapter constitute the TR Federal Implementation Plan provisions that relate to annual emissions of nitrogen oxides (NO X ).

(2) The provisions of subpart AAAAA of part 97 of this chapter, regarding the

TR NO X Annual Trading Program, apply to the sources in the following States: Alabama, Connecticut, Delaware, District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and

Wisconsin.

(3) Following promulgation of an approval by the Administrator of a State’s SIP as correcting the SIP’s deficiency that is the basis for this Federal Implementation Plan, the provisions of paragraph (a)(2) of this section will no longer apply to the sources in the State, unless the Administrator’s approval of the SIP is partial or conditional.

(4) Notwithstanding the provisions of paragraph (a)(3) of this section, if, at the time of such approval of the State’s SIP, the Administrator has already allocated any TR NO X Annual allowances to sources in the State for any years, the provisions of part 97 of this chapter authorizing the Administrator to complete the allocation of TR NO X Annual allowances for those years shall continue to apply, unless provided otherwise by such approval of the

State’s SIP.

(b)(1) The TR NO X Ozone Season Trading Program provisions of part 97 of this chapter constitute the TR Federal Implementation Plan provisions that
relate to emissions of NO X during the ozone season, defined as May 1 through September 30 of a calendar year.

(2) The provisions of subpart BBBBB of part 97 of this chapter, regarding the

TR NO X Ozone Season Trading Program, apply to sources in each of the following States: 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 Virginia.

(3) Following promulgation of an approval by the Administrator of a State’s SIP as correcting the SIP’s deficiency that is the basis for this Federal Implementation Plan, the provisions of paragraph (b)(2) of this section will no longer apply to sources in the State, unless the Administrator’s approval of the SIP is partial or
conditional.

(4) Notwithstanding the provisions of paragraph (b)(3) of this section, if, at the time of such approval of the State’s SIP, the Administrator has already allocated any TR NO X Ozone Season allowances to sources in the State for any years, the provisions of part 97 of this chapter authorizing the Administrator to complete the allocation of TR NO X Ozone Season allowances for those years shall continue to apply, unless provided otherwise by such approval of
the State’s SIP.


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**§ 52.38 What are the requirements of the Federal Implementation Plans (FIPs) for the**  **Transport Rule (TR) relating to emissions of**
**sulfur dioxide?**

(a) The TR SO 2 Group 1 Trading Program and TR SO 2 Group 2 Trading Program provisions of part 97 of this chapter constitute the TR Federal Implementation Plan provisions that
relate to emissions of sulfur dioxide (SO 2 ).

(b) The provisions of subpart CCCCC of part 97 of this chapter, regarding the

TR SO 2 Group 1 Trading Program, apply to sources in each of the following States: Georgia, Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin.

(c) The provisions of subpart DDDDD of part 97 of this chapter, regarding the

TR SO 2 Group 2 Trading Program, apply to sources in each of the following States: Alabama, Connecticut, Delaware, District of Columbia, Florida, Kansas, Louisiana, Maryland, Massachusetts, Minnesota, Nebraska, New Jersey, and
South Carolina.

(d) Following promulgation of an approval by the Administrator of a State’s SIP as correcting the SIP’s deficiency that is the basis for this Federal Implementation Plan, the provisions of paragraph (b) and (c) of this section, as applicable, will no longer apply to sources in the State, unless the Administrator’s approval of the SIP is partial or conditional.

(e) Notwithstanding the provisions of paragraph (d) of this section, if, at the time of such approval of the State’s SIP, the Administrator has already allocated any TR SO 2 Group 1 allowances or any

TR SO 2 Group 2 allowances (as applicable) to sources in the State for any years, the provisions of part 97 of this chapter authorizing the Administrator to complete the
allocation of TR SO 2 Group 1
allowances or TR SO 2 Group 2 allowances (as applicable) for those years shall continue to apply, unless provided otherwise by such approval of
the State’s SIP.

**Subpart I—Delaware**

10. Section 52.440 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.440 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

11. Section 52.441 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.441 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**Subpart J—District of Columbia**

12. Section 52.484 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.484 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

13. Section 52.485 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.485 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**Subpart P—Indiana**

14. Section 52.789 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.789 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

15. Section 52.790 is amended by designating the introductory text as


### 45364 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.790 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**Subpart T—Louisiana**

16. Section 52.984 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.984 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

**Subpart X—Michigan**

17. Section 52.1186 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.1186 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * * (c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

18. Section 52.1187 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.1187 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**Subpart FF—New Jersey**

19. Section 52.1584 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.1584 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

20. Section 52.1185 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.1585 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**Subpart RR—Tennessee**

21. Section 52.2240 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.2240 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X


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allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

22. Section 52.2241 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.2241 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**Subpart SS—Texas**

23. Section 52.2283 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.2283 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraph (a) of this section relating to NO X annual emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances allocated for 2012 or any year thereafter.

24. Section 52.2284 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.2284 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**Subpart YY—Wisconsin**

25. Section 52.8587 is amended by adding a new paragraph (c) to read as
follows:

**§ 52.8587 Interstate pollutant transport provisions; What are the FIP requirements**  **for decreases in emissions of nitrogen**
**oxides?**

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section relating to NO X annual or ozone season emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR NO X allowances or CAIR NO X Ozone Season allowances allocated for 2012 or any year thereafter.

26. Section 52.8588 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:

**§ 52.8588 Interstate pollutant transport provisions; What are the FIP requirements** 
**for decreases in emissions of sulfur**
**dioxide?**

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State’s SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2011,

(i) The provisions of paragraph (a) of this section relating to SO 2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any CAIR SO 2 allowances allocated for 2012 or any year thereafter.

**PART 72—[AMENDED]**

27. The authority citation for Part 72
is revised to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7410,

7411, 7426, 7601, et seq.

**§ 72.2 [Amended]**

28. Section 72.2 is amended by removing the definition of ‘‘ interested

person ’’

.
**PART 78—[AMENDED]**

29. The authority citation for Part 78
continues to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7410,

7411, 7426, 7601, et seq.

**§ 78.1 [Amended]**

30. Section 78.1 is amended by adding paragraphs (b)(13) through (b)(16) to read as follows:

**§ 78.1 Purpose and scope.**

* * * * *

(b) * * * (13) Under subpart AAAAA of part 97 of this chapter,

(i) The decision on allocation of TR

NO X Annual allowances under § 97.411(a)(2) and (b) of this chapter.

(ii) The decision on the transfer of TR

NO X Annual allowances under § 97.423 of this chapter.

(iii) The decision on the deduction of

TR NO X Annual allowances under §§ 97.424 and 97.425 of this chapter.

(iv) The correction of an error in an Allowance Management System account under § 97.427 of this chapter.

(iv) The adjustment of information in
a submission and the decision on the
deduction and transfer of TR NO X Annual allowances based on the information as adjusted under § 97.428 of this chapter.

(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.

(vii) The approval or disapproval of a petition under § 97.435 of this chapter.

(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw,
the decision on allocation of TR NO X Annual allowances, and the decision on
the deduction of TR NO X Annual allowances under §§ 97.441 through

97.444.

(14) Under subpart BBBBB of part 97 of this chapter, (i) The decision on
allocation of TR NO X Ozone Season


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allowances under § 97.511(a)(2) and (b) of this chapter.

(ii) The decision on the transfer of TR

NO X Ozone Season allowances under § 97.523 of this chapter.

(iii) The decision on the deduction of

TR NO X Ozone Season allowances under §§ 97.524 and 97.525 of this chapter.

(iv) The correction of an error in an Allowance Management System account under § 97.527 of this chapter.

(iv) The adjustment of information in
a submission and the decision on the
deduction and transfer of TR NO X Ozone Season allowances based on the information as adjusted under § 97.528 of this chapter.

(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.

(vii) The approval or disapproval of a petition under § 97.535 of this chapter.

(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw,
the decision on allocation of TR NO X Ozone Season allowances, and the
decision on the deduction of TR NO X Ozone Season allowances under §§ 97.541 through 97.544.

(15) Under subpart CCCCC of part 97 of this chapter,

(i) The decision on allocation of TR

SO 2 Group 1 allowances under § 97.611(a)(2) and (b) of this chapter.

(ii) The decision on the transfer of TR

SO 2 Group 1 allowances under § 97.623 of this chapter.

(iii) The decision on the deduction of

TR SO 2 Group 1 allowances under §§ 97.624 and 97.625 of this chapter.

(iv) The correction of an error in an Allowance Management System account under § 97.627 of this chapter.

(iv) The adjustment of information in
a submission and the decision on the
deduction and transfer of TR SO 2 Group
1 allowances based on the information as adjusted under § 97.628 of this chapter.

(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.

(vii) The approval or disapproval of a petition under § 97.635 of this chapter.

(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw,
the decision on allocation of TR SO 2 Group 1 allowances, and the decision
on the deduction of TR SO 2 Group 1 allowances under §§ 97.641 through

97.644.

(16) Under subpart DDDDD of part 97 of this chapter,

(i) The decision on allocation of TR

SO 2 Group 2 allowances under § 97.711(a)(2) and (b) of this chapter. (ii) The decision on the transfer of TR

SO 2 Group 1 allowances under § 97.723 of this chapter.

(iii) The decision on the deduction of

TR SO 2 Group 1 allowances under §§ 97.724 and 97.725 of this chapter.

(iv) The correction of an error in an Allowance Management System account under § 97.727 of this chapter.

(iv) The adjustment of information in
a submission and the decision on the
deduction and transfer of TR SO 2 Group
1 allowances based on the information as adjusted under § 97.728 of this chapter.

(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.

(vii) The approval or disapproval of a petition under § 97.735 of this chapter.

(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw,
the decision on allocation of TR SO 2 Group 2 allowances, and the decision
on the deduction of TR SO 2 Group 2 allowances under §§ 97.741 through

97.744.

* * * * *

**§ 78.2 [Amended]**

31. Section 78.2 is revised to read as
follows:

**§ 78.2 General.**

(a) Definitions. (1) The terms used in this subpart with regard to a decision of the Administrator that is appealed
under this section shall have the meaning as set forth in the regulations
under which the Administrator made
such decision and as set forth in paragraph (a)(2) of this section.

(2) Interested person means, with regard to a decision of the Administrator, any person who submitted comments, or testified at a public hearing, pursuant to an opportunity for comment provided by the Administrator as part of the process of making such decision, who submitted objections pursuant to an opportunity for objections provided by the Administrator as part of the process of making such decision, or who submitted
his or her name to the Administrator to be placed on a list of persons interested
in such decision. The Administrator may update the list of interested persons from time to time by requesting
additional written indication of continued interest from the persons listed and may delete from the list the name of any person failing to respond as requested.

(b) Availability of information. The availability to the public of information provided to, or otherwise obtained by, the Administrator under this subpart shall be governed by part 2 of this chapter.

(c) Computation of time. (1) In computing any period of time prescribed or allowed under this part, except as otherwise provided, the day of the event from which the period begins to run shall not be included, and Saturdays, Sundays, and federal holidays shall be included. When the period ends on a Saturday, Sunday, or Federal holiday, the stated period shall
be extended to include the next business day.

(2) Where a document is served by first class mail or commercial deliveryservice, but not by overnight or sameday delivery, 5 days shall be added to the time prescribed or allowed under this part for the filing of a responsive document or for otherwise responding.

**§ 78.3 [Amended]**

32. Section 78.3 is amended by: a. In paragraphs (a)(1)(iii), (a)(3)(ii), (a)(4)(ii), (a)(5)(ii), (a)(6)(ii), (a)(7)(ii), (a)(8)(ii), and (a)(9)(ii), adding, after the
word ‘‘ person ’’ , the words ‘‘ with regard
to the decision ’’

.

b. Adding paragraph (a)(10); c. In paragraph (b)(3)(i), removing the
words ‘‘ paragraph (a)(1) and (2) ’’ and adding, in their place, the words

‘‘ paragraph (a)(1), (2), and (10) ’’ ; and

d. Adding paragraph (d)(11) to read as
follows:

**§ 78.3 Petition for administrative review and request or evidentiary hearing.** 

(a) * * * (10) The following persons may petition for administrative review of a
decision of the Administrator that is made under subparts AAAAA, BBBBB, CCCCC, and DDDDD of part 97 of this chapter:

(i) The designated representative for a unit or source, or the authorized account representative for any Allowance Management System account, covered by the decision; or

(ii) Any interested person with regard
to the decision.

* * * * *

(d) * * * (11) Any provision or requirement of subparts AAAAA, BBBBB, CCCCC, or DDDDD of part 97 of this chapter, including the standard requirements under § 97.406, § 97.506, § 97.606, or § 97.706 of this chapter and any emission monitoring or reporting requirements.

**§ 78.4 [Amended]**

33. Section 78.4 is amended by: a. Revising paragraph (a) by: i. Removing the first, second, third, fourth, fifth, and last sentences;


### 45367 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

ii. In the sixth and seventh sentences, removing the words ‘‘ interest in ’’ and adding, in their place, the words

‘‘ ownership interest with respect to ’’ ; and

iii. Redesignating the paragraph as paragraph (a)(1)(iii); and

b. Adding paragraphs (a)(1) introductory text, (a)(1)(i), (a)(1)(ii) and (a)(2) to read as follows:

**§ 78.4 Filings.**

(a)(1) All original filings made under this part shall be signed by the person making the filing or by an attorney or authorized representative, in accordance with the following requirements:

(i) Any filings on behalf of owners and operators of a affected unit or affected source, TR NO X Annual unit or

TR NO X Annual source, TR NO X Ozone

Season unit or TR NO X Ozone Season source, TR SO 2 Group 1 unit or TR SO 2 Group 1 source, TR SO 2 Group 2 unit or

TR SO 2 Group 2 source, or a unit for which a TR opt-in application is
submitted and not withdrawn shall be signed by the designated representative. Any filing on behalf of persons with an ownership interest with respect to allowances, TR NO X Annual allowances, TR NO X Ozone Season allowances, TR SO 2 Group 1 allowances, or TR SO 2 Group 2 allowances in a general account shall be signed by the authorized account representative.

(ii) Any filings on behalf of owners and operators of a NO X Budget unit or

NO X Budget source shall be signed by
the NO X authorized account representative. Any filing on behalf of persons with an ownership interest with respect to NO X allowances in a general account shall be signed by the NO X authorized account representative.

* * * * *

(2) The name, address, e-mail address (if any), telephone number, and facsimile number (if any) of the person making the filing shall be provided with the filing.

* * * * *

**PART 97—[AMENDED]**

34. The authority citation for part 97
continues to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et seq.

35. Part 97 is amended by adding subpart AAAAA to read as follows:

**Subpart AAAAA TR NO** X **Annual Trading Program** 

Sec. 97.401 Purpose. 97.402 Definitions. 97.403 Measurements, abbreviations, and

acronyms. 97.404 Applicability. 97.405 Retired unit exemption. 97.406 Standard requirements. 97.407 Computation of time. 97.408 Administrative appeal procedures. 97.409 [Reserved]

97.410 State NO X Annual trading budgets, new-unit set-asides, and variability
limits. 97.411 Timing requirements for TR NO X Annual allowance allocations.

97.412 TR NO X Annual allowance
allocations for new units. 97.413 Authorization of designated representative and alternate designated representative. 97.414 Responsibilities of designated representative and alternate designated representative. 97.415 Changing designated representative and alternate designated representative; changes in owners and operators. 97.416 Certificate of representation. 97.417 Objections concerning designated representative and alternate designated representative. 97.418 Delegation by designated representative and alternate designated representative. 97.419 [Reserved]
97.420 Establishment of Allowance Management System accounts.
97.421 Recordation of TR NO X Annual
allowance allocations.
97.422 Submission of TR NO X Annual
allowance transfers.
97.423 Recordation of TR NO X Annual
allowance transfers. 97.424 Compliance with TR NO X Annual
emissions limitation. 97.425 Compliance with TR NO X Annual assurance provisions. 97.426 Banking.

97.427 Account error. 97.428 Administrator’s action on
submissions. 97.429 [Reserved] 97.430 General monitoring, recordkeeping, and reporting requirements. 97.431 Initial monitoring system
certification and recertification procedures. 97.432 Monitoring system out-of-control periods. 97.433 Notifications concerning monitoring. 97.434 Recordkeeping and reporting.
97.435 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements. 97.440 General requirements for TR NO X Annual opt-in units. 97.441 Opt-in process.
97.442 Withdrawal of TR NO X Annual optin unit from TR NO X Annual Trading Program. 97.443 Change in regulatory status.

97.444 TR NO X Annual allowance
allocations to TR NO X Annual opt-in

units.

**Subpart AAAAA—TR NO** X **Annual Trading Program** 

**§ 97.401 Purpose.**

This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) NO X Annual Trading Program, under section 110 of the Clean Air Act and § 52.37(a) of this chapter, as a means of mitigating interstate transport of fine particulates and nitrogen oxides.

**§ 97.402 Definitions.**

The terms used in this subpart shall have the meanings set forth in this
section as follows:

Acid Rain Program means a multistate SO 2 and NO X air pollution control and emission reduction program established by the Administrator under title IV of the Clean Air Act and parts 72 through 78 of this chapter.

Administrator means the
Administrator of the United States Environmental Protection Agency or the
Director of the Clean Air Markets Division (or its successor) of the United
States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.

Allocate or allocation means, with regard to TR NO X Annual allowances, the determination by the Administrator
of the amount of such TR NO X Annual allowances to be initially credited to a

TR NO X Annual source or a new unit
set-aside.

Allowable NO X emission rate means, with regard to a unit, the NO X emission rate limit that is applicable to the unit and covers the longest averaging period not exceeding one year.

Allowance Management System means the system by which the Administrator records allocations, deductions, and transfers of TR NO X Annual allowances under the TR NO X Annual Trading Program. Such allowances are allocated, held, deducted, or transferred only as whole
allowances. The Allowance Management System is a component of the CAMD Business System, which is the system used by the Administrator to
handle TR NO X Annual allowances and
data related to NO X emissions.

Allowance Management System

account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, holding, transfer, or deduction of TR

NO X Annual allowances.

Allowance transfer deadline means, for a control period, midnight of March 1 (if it is a business day), or midnight of the first business day thereafter (if March 1 is not a business day), immediately after such control period and is the deadline by which a TR NO X Annual allowance transfer must be
submitted for recordation in a TR NO X


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Annual source’s compliance account in
order to be available for use in complying with the source’s TR NO X Annual emissions limitation for such control period in accordance with § 97.424.

Alternate designated representative means, for a TR NO X Annual source and
each TR NO X Annual unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with this subpart, to act on behalf of the designated representative in matters pertaining to the TR NO X Annual Trading Program. If the TR NO X Annual source is also subject to the Acid Rain Program, TR NO X Ozone Season Trading Program, TR SO 2 Group 1 Trading Program, or TR SO 2 Group 2 Trading Program, then this natural person shall be the same natural person as the alternate designated representative as defined in § 72.2 of this chapter, § 97.502, § 97.602, or § 97.702 respectively.

Authorized account representative means, with regard to a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of TR NO X Annual allowances held in the general account and, with regard to a TR NO X Annual source’s compliance account, the designated representative of the

source.

Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a
continuous record of the measured parameters in the measurement units required by this subpart.

Biomass means
— (1) Any organic material grown for the purpose of being converted to energy;

(2) Any organic byproduct of agriculture that can be converted into

energy; or

(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from
other material that is nonmerchantable for other purposes, and that is;

(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct
from conversion of trees to merchantable material; or

(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.

Boiler means an enclosed fossil-or
other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other
medium.

Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

Certifying official means a natural person who is:

(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;

(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or

(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking
elected official.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.

Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.

Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

Coal-fired means combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during 1990 or any year thereafter.

Cogeneration system means an integrated group, at a source, of equipment (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 electricity through the sequential use of energy.

Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine—

(1) Operating as part of a cogeneration system; and

(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—

(i) For a topping-cycle unit, (A) Useful thermal energy not less than 5 percent of total energy output;
and (B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.

(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;

(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler;
and

(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and thecogeneration system meets on a systemwide basis the requirement in paragraph(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such requirement during that calendar year.

Combustion turbine means an enclosed device comprising:

(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from
the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and

(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.

Commence commercial operation means, with regard to a unit:

(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.405.

(i) For a unit that is a TR NO X Annual unit under § 97.404 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such
date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit that is a TR NO X Annual unit under § 97.404 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the


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replacement unit shall be treated as a separate unit with a separate date for
commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.405, for a unit that is not a TR

NO X Annual unit under § 97.404 on the later of November 15, 1990 or the date
the unit commences commercial operation as defined in introductory text of paragraph (1) of this definition, the
unit’s date for commencement of commercial operation shall be the date
on which the unit becomes a TR NO X Annual unit under § 97.404.

(i) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source),
such date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of
commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

Commence operation means, with regard to a unit:

(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit’s
combustion chamber.

(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source)
after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be
treated as the same unit.

(3) For a unit that is replaced by a unit
at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate. Common stack means a single flue through which emissions from 2 or
more units are exhausted.

Compliance account means an Allowance Management System account, established by the
Administrator for a TR NO X Annual source under this subpart, in which any

TR NO X Annual allowance allocations
for the TR NO X Annual units at the
source are recorded and in which are held any TR NO X Annual allowances available for use for a control period in complying with the source’s TR NO X Annual emissions limitation in accordance with § 97.424 and the TR

NO X Annual assurance provisions in accordance with § 97.425.

Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent
record of NO X emissions, stack gas volumetric flow rate, stack gas moisture content, and O 2 or CO 2 concentration (as applicable), in a manner consistent with part 75 of this chapter and §§ 97.430 through 97.435. The following systems are the principal types of continuous emission monitoring systems:

(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A NO X concentration monitoring system, consisting of a NO X pollutant
concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of NO X emissions, in parts per million (ppm);

(3) A NO X emission rate (or NO X diluent) monitoring system, consisting
of a NO X pollutant concentration monitor, a diluent gas (CO 2 or O 2 ) monitor, and an automated data acquisition and handling system and providing a permanent, continuous
record of NO X concentration, in parts per million (ppm), diluent gas concentration, in percent CO 2 or O 2 , and

NO X emission rate, in pounds per million British thermal units (lb/ mmBtu);

(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H 2 O;

(5) A CO 2 monitoring system, consisting of a CO 2 pollutant concentration monitor (or an O 2 monitor plus suitable mathematical equations
from which the CO 2 concentration is derived) and an automated data acquisition and handling system and providing a permanent, continuous
record of CO 2 emissions, in percent CO 2 ; and

(6) An O 2 monitoring system, consisting of an O 2 concentration
monitor and an automated data acquisition and handling system and providing a permanent, continuous
record of O 2 , in percent O 2

.

Control period means the period starting January 1 of a calendar year, except as provided in § 97.406(c)(3), and ending on December 31 of the same year, inclusive.

Designated representative means, for

a TR NO X Annual source and each TR

NO X Annual unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with this subpart, to represent and legally bind each owner and operator in matters pertaining to the

TR NO X Annual Trading Program. If the

TR NO X Annual source is also subject to the Acid Rain Program, TR NO X Ozone Season Trading Program, TR SO 2 Group 1 Trading Program, or TR SO 2 Group 2 Trading Program, then this natural person shall be the same natural person as the designated representative, as defined in § 72.2 of this chapter, § 97.502, § 97.602, or § 97.702 respectively.

Emissions means air pollutants
exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart.

Excess emissions means any ton of

NO X emitted from the TR NO X Annual

units at a TR NO X Annual source during a control period that exceeds the TR

NO X Annual emissions limitation for
the source.

Fossil fuel means— (1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or

(2) For purposes of applying §§ 97.404(b)(2)(i)(B), 97.404(b)(2)(ii)(B), and 97.404(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating
useful heat.

Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 1990 or any calendar year
thereafter.

Fuel oil means any petroleum-based fuel (including diesel fuel or petroleum derivatives such as oil tar) and any


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recycled or blended petroleum products or petroleum by-products used as a fuel whether in a liquid, solid, or gaseous

state.

General account means an Allowance Management System account, established under this subpart, that is not a compliance account.

Generator means a device that produces electricity.

Gross electrical output means, with regard to a unit, electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Heat input means, with regard to a unit for a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the designated representative and as modified by the
Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.

Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the
fuel.

Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:

(1) For the life of the unit; (2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination;

or (3) For a period no less than 25 years or 70 percent of the economic useful life
of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as of
the initial installation of the unit as specified by the manufacturer of the

unit.

Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.

Nameplate capacity means, starting
from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of such completion as specified by the person conducting the physical change.

Newly affected TR NO X Annual unit
means a unit that was not a TR NO X Annual unit when it began operating
but that thereafter becomes a TR NO X Annual unit.

Operate or operation means, with regard to a unit, to combust fuel.

Operator means any person who operates, controls, or supervises a TR

NO X Annual unit or a TR NO X Annual source and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit

or source.

Owner means, with regard to a TR

NO X Annual source or a TR NO X Annual unit at a source respectively, any of the following persons:

(1) Any holder of any portion of the legal or equitable title in a TR NO X Annual unit at the source or the TR NO X Annual unit;

(2) Any holder of a leasehold interest

in a TR NO X Annual unit at the source
or the TR NO X Annual unit, provided that, unless expressly provided for in a leasehold agreement, ‘‘ owner ’’ shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly)
on the revenues or income from such TR

NO X Annual unit;

(3) Any purchaser of power from a TR

NO X Annual unit at the source or the TR

NO X Annual unit under a life-of-theunit, firm power contractual arrangement; (4) Provided that, for purposes of applying the TR NO X Annual assurance provisions in §§ 97.406(c)(2) and 97.425, if one or more owners (as defined in paragraphs (1) through (3) of this definition) of one or more TR NO X Annual units in a State are wholly owned by another, common owner, all such owners shall be treated collectively as a single owner in the State.

Owner’s assurance level means: (1) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.406(c)(2)(iii)(A) and not as described in § 97.406(c)(2)(iii)(B), the
owner’s share of the State NO X Annual trading budget with the one-year variability limit for the State for such control period; or

(2) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.406(c)(2)(iii)(B), the owner’s share
of the State NO X Annual trading budget with the three-year variability limit for the State for such control period.

Owner’s share means: (1) With regard to a total amount of

NO X emissions from all TR NO X Annual units in a State during a control period, the total tonnage of NO X emissions during such control period from all of
the owner’s TR NO X Annual units in the State;

(2) With regard to a State NO X Annual trading budget with a one-year variability limit for a control period, the amount (rounded to the nearest allowance) equal to the total amount of

TR NO X Annual allowances allocated for such control period to all of the

owner’s TR NO X Annual units in the State, multiplied by the sum of the State

NO X Annual trading budget under § 97.410(a) and the State’s one-year variability limit under § 97.410(b) and divided by such State NO X Annual trading budget;

(3) With regard to a State NO X Annual trading budget with a three-year variability limit for a control period, the amount (rounded to the nearest allowance) equal to the total amount of

TR NO X Annual allowances allocated for such control period to all of the

owner’s TR NO X Annual units in the State, multiplied by the sum of the State

NO X Annual trading budget under § 97.410(a) and the State’s three-year variability limit under § 97.410(b) and divided by such State NO X Annual trading budget;

(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of NO X emissions and of TR

NO X Annual allowances allocated for a control period, with regard to such unit, used in determining each owner’s share


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shall be the amount (rounded to the nearest ton and the nearest allowance) equal to the unit’s NO X emissions and allocation of such allowances, respectively, for such control period multiplied by the percentage of ownership in the unit that the owner’s legal, equitable, leasehold, or
contractual reservation or entitlement in the unit comprises as of December 31 of such control period;

(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which

NO X mass emissions are reported for a control period for a year, the amount of tonnage of each unit’s NO X emissions used in determining each owner’s share for such control period shall be:

(i) The amount (rounded to the nearest ton) of NO X emissions reported at the common stack multiplied by the quotient of such unit’s heat input for such control period divided by the total heat input reported from the common stack for such control period;

(ii) An amount determined in accordance with a methodology that the
Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the
Administrator determines will be de

minimis ; or

(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.435; and

(6) Provided that, in the case of a unit that operates during, but is allocated no

TR NO X Annual allowances for, a control period, the unit shall be treated, solely for purposes of this definition, as being allocated an amount (rounded to the nearest allowance) of TR NO X Annual allowances for such control period equal to the lesser of—

(i) The unit’s allowable NO X emission rate (in lb per MWe) applicable to such control period, multiplied by a capacity factor of 0.84 (if the unit is a coal-fired boiler), 0.15 (if the unit is a simple combustion turbine), or 0.66 (if the unit is a combined cycle turbine), multiplied by the unit’s maximum hourly load as reported in accordance with this subpart and by 8,760 hours/control period, and divided by 2,000 lb/ton; or

(ii) For a unit listed in appendix A to this subpart, the sum of the unit’s NO X emissions in the control period in the last three years during which the unit operated during the control period, divided by three.

Permanently retired means, with regard to a unit, a unit that is
unavailable for service and that the unit’s owners and operators do not expect to return to service in the future. Permitting authority means

‘‘ permitting authority ’’ as defined in §§ 70.2 and 71.2 of this chapter.

Potential electrical output capacity means 33 percent of a unit’s maximum design heat input, divided by 3,413 Btu/ kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.

Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of
business.

Recordation, record, or recorded means, with regard to TR NO X Annual allowances, the moving of TR NO X Annual allowances by the Administrator into, out of, or between Allowance Management System accounts, for purposes of allocation, transfer, or deduction.

Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.

Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used
instead of the demolished or retired unit (the replaced unit).

Sequential use of energy means: (1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application

or process; or

(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.

Serial number means, for a TR NO X Annual allowance, the unique identification number assigned to each

TR NO X Annual allowance by the
Administrator.

Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion
turbine that is a ‘‘ solid waste

incineration unit ’’ as defined in section 129(g)(1) of the Clean Air Act.

Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the
definition of ‘‘ major source, ’’ ‘‘ stationary

source, ’’ or ‘‘ source ’’ as set forth and implemented in a title V operating permit program or any other program
under the Clean Air Act.

State means one of the States or the District of Columbia that is subject to
the TR NO X Annual Trading Program pursuant to § 52.37(a) of this chapter.

Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(1) In person; (2) By United States Postal Service; or (3) By other means of dispatch or transmission and delivery;

(4) Provided that compliance with any

‘‘ submission ’’ or ‘‘ service ’’ deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.

Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.

Total energy input means total energy of all forms supplied to a unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as
follows:

LHV = HHV ¥ 10.55(W + 9H)

Where: LHV = lower heating value of the form of energy in Btu/lb, HHV = higher heating value of the form of energy in Btu/lb, W = weight % of moisture in the form of energy, and H = weight % of hydrogen in the form of

energy. Total energy output means the sum of useful power and useful thermal energy produced by the unit.

TR NO X Annual allowance means a limited authorization issued and allocated by the Administrator under this subpart to emit one ton of NO X during a control period of the specified calendar year for which the authorization is allocated or of any calendar year thereafter under the TR

NO X Annual Program.

TR NO X Annual allowance deduction
or deduct TR NO X Annual allowances means the permanent withdrawal of TR

NO X Annual allowances by the Administrator from a compliance

account, e.g. , in order to account for compliance with the TR NO X Annual
emissions limitation or assurance provisions.

TR NO X Annual allowances held or
hold TR NO X Annual allowances means the TR NO X Annual allowances treated


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as included in an Allowance Management System account as of a specified point in time because at that time they:

(1) Have been recorded by the
Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR NO X Annual allowance transfer in accordance with this subpart;
and

(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR NO X Annual
allowance transfer in accordance with this subpart.

TR NO X Annual Trading Program
means a multi-state NO X air pollution control and emission reduction program established by the Administrator in accordance with this subpart and 52.37(a) of this chapter, as a means of mitigating interstate transport of fine particulates and NO X
.

TR NO X Annual emissions limitation means, for a TR NO X Annual source, the tonnage of NO X emissions authorized in a control period by the TR NO X Annual
allowances available for deduction for the source under § 97.424(a) for such control period.

TR NO X Annual source means a source that includes one or more TR

NO X Annual units.

TR NO X Annual unit means a unit that is subject to the TR NO X Annual Trading Program under § 97.404.

TR NO X Ozone Season Trading Program means a multi-state NO X air pollution control and emission reduction program established by the
Administrator in accordance with subpart BBBBB of this part and 52.37(b) of this chapter, as a means of mitigating interstate transport of ozone and NO X
.

TR SO 2 Group 1 Trading Program
means a multi-state SO 2 air pollution control and emission reduction program established by the Administrator in accordance with subpart CCCCC of this part and 52.38(b) of this chapter, as a means of mitigating interstate transport of fine particulates and SO 2

.

TR SO 2 Group 2 Trading Program
means a multi-state SO 2 air pollution control and emission reduction program established by the Administrator in accordance with subpart DDDDD of this part and 52.38(c) of this chapter, as a means of mitigating interstate transport of fine particulates and SO 2

.

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary,
fossil-fuel-fired combustion device. Unit operating day means a calendar day in which a unit combusts any fuel.

Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.

Useful power means electricity or mechanical energy that a unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means thermal energy that is:

(1) Made available to an industrial or commercial process (not a power production process), excluding any heat
contained in condensate return or makeup water;

(2) Used in a heating application ( e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application ( i.e., in an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to

customers.

**§ 97.403 Measurements, abbreviations, and acronyms.** 

Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:

Btu—British thermal unit

CO 2 —carbon dioxide

H 2 O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour lb—pound
mmBtu—million Btu MWe—megawatt electrical MWh—megawatt hour

NO X —nitrogen oxides

O 2 —oxygen ppm—parts per million scfh—standard cubic feet per hour

SO 2 —sulfur dioxide

yr—year

**§ 97.404 Applicability.**

(a) Except as provided in paragraph (b) of this section:

(1) The following units in a State shall
be TR NO X Annual units, and any
source that includes one or more such
units shall be a TR NO X Annual source, subject to the requirements of this subpart: 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 chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. (2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a

TR NO X Annual unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the
unit shall become a TR NO X Annual unit as provided in paragraph (a)(1) of
this section on the first date on which
it both combusts fossil fuel and serves such generator.

(b) Any unit in a State that otherwise

is a TR NO X Annual unit under paragraph (a) of this section and that meets the requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR NO X Annual unit:

(1)(i) Any unit: (A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and

(B) Not serving at any time, since thelater of November 15, 1990 or the startup of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system
for sale.

(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12- month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the
unit shall become a TR NO X Annual unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of paragraph (b)(1)(i)(B) of this section.

(2)(i) Any unit commencing operation before January 1, 1985:

(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average annual fuel consumption of fossil fuel for 1985– 1987 less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(ii) Any unit commencing operation on or after January 1, 1985:


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(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average annual fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a

TR NO X Annual unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a solid waste incineration unit or January 1 after the first 3 consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of fossil fuel of 20 percent or more.

(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR NO X Annual Trading Program to the unit or other equipment.

(1) Petition content. The petition shall be in writing and include the
identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying
official: ‘‘ I am authorized to make this
submission on behalf of the owners and operators of the unit or other equipment
for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR NO X Annual Trading Program to the unit or other equipment shall be binding on any permitting authority unless the
Administrator determines that the petition or other documents or information provided in connection with the petition contained significant,
relevant errors or omissions.

**§ 97.405 Retired unit exemption.**

(a)(1) Any TR NO X Annual unit that is permanently retired and is not a TR

NO X Annual opt-in unit shall be exempt from § 97.406(b) and (c)(1), § 97.424, and §§ 97.430 through 97.435.

(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR NO X Annual unit is permanently retired. Within 30 days of the unit’s permanent retirement, the designated representative shall submit a statement
to the Administrator. The statement shall state, in a format prescribed by the Administrator, that the unit was permanently retired on a specified date and will comply with the requirements of paragraph (b) of this section.

(b) Special provisions. (1) A unit exempt under paragraph (a) of this section shall not emit any NO X , starting on the date that the exemption takes
effect.

(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR

NO X Annual Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (4) A unit exempt under paragraph (a) of this section shall lose its exemption
on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.

**§ 97.406 Standard requirements.**

(a) Designated representative requirements . The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.413 through 97.418.

(b) Emissions monitoring, reporting, and recordkeeping requirements . (1) The owners and operators, and the designated representative, of each TR

NO X Annual source and each TR NO X Annual unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of §§ 97.430 through 97.435.

(2) The emissions data determined in accordance with §§ 97.430 through
97.435 shall be used to calculate
allocations of TR NO X Annual allowances under §§ 97.411(a)(2) and (b)
and 97.412 and to determine compliance with the TR NO X Annual
emissions limitation and assurance provisions under paragraph (c) of this section, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location
determined in accordance with §§ 97.430 through 97.435 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be

zero.

(c) NO X emissions requirements. (1)

TR NO X Annual emissions limitation. (i)
As of the allowance transfer deadline for a control period, the owners and operators of each TR NO X Annual
source and each TR NO X Annual unit at the source shall hold, in the source’s compliance account, TR NO X Annual
allowances available for deduction for such control period under § 97.424(a) in
an amount not less than the tons of total

NO X emissions for such control period
from all TR NO X Annual units at the

source.

(ii) If a TR NO X Annual source emits

NO X during any control period in excess
of the TR NO X Annual emissions limitation set forth in paragraph (c)(1)(i) of this section, then:


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(A) The owners and operators of the
source and each TR NO X Annual unit at
the source shall hold the TR NO X Annual allowances required for deduction under § 97.424(d) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act; and

(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.

(2) TR NO X Annual assurance provisions. (i) If the total amount of

NO X emissions from all TR NO X Annual units in a State during a control period in 2014 or any year thereafter exceeds
the State assurance level as described in paragraph (c)(2)(iii) of this section, then
each owner whose share of such NO X emissions during such control period
exceeds the owner’s assurance level for the State and such control period shall hold, in a compliance account designated by the owner in accordance with § 97.425(b)(4)(ii), TR NO X Annual
allowances available for deduction for such control period under § 97.425(a) in an amount equal to the product, as determined by the Administrator in accordance with § 97.425(b), of multiplying—

(A) The quotient (rounded to the nearest whole number) of the amount by
which the owner’s share of such NO X emissions exceeds the owner’s assurance level divided by the sum of the amounts, determined for all such owners, by which each owner’s share of
such NO X emissions exceeds that owner’s assurance level; and

(B) The amount by which total NO X emissions for all TR NO X Annual units in the State for such control period
exceed the State assurance level as
determined in accordance with paragraph (c)(2)(iii) of this section.

(ii) The owner shall hold the TR NO X Annual allowances required under paragraph (c)(2)(i) of this section, as of midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such control period.

(iii) The total amount of NO X emissions from all TR NO X Annual units in a State during a control period in 2014 or any year thereafter exceeds
the State assurance level:

(A) If such total amount of NO X emissions exceeds the sum, for such control period, of the State NO X Annual trading budget and the State’s one-year variability limit under § 97.410(b); or

(B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount of NO X emissions and the total amounts
of NO X emissions from all TR NO X Annual units in the State during the control periods in the immediately preceding two years exceeds the sum, for such control period, of the State NO X Annual trading budget and the State’s three-year variability limit under § 97.410(b);

(C) Provided that the amount by
which such total amount of NO X emissions exceeds the State assurance level shall be the greater of the amounts
of the exceedance calculated under paragraph (c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of this

section.

(iv) It shall not be a violation of this subpart or of the Clean Air Act if the
total amount of NO X emissions from all

TR NO X Annual units in a State during a control period exceeds the State
assurance level or if an owner’s share of
total NO X emissions from the TR NO X Annual units in a State during a control period exceeds the owner’s assurance
level.

(v) To the extent an owner fails to
hold TR NO X Annual allowances for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section,

(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and

(B) Each TR NO X Annual allowance
that the owner fails to hold for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.

(3) Compliance periods . A TR NO X Annual unit shall be subject to the requirements:

(i) Under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2012 or the deadline for meeting the unit’s monitor certification requirements under § 97.430(b) and for each control period thereafter; and

(ii) Under paragraph (c)(2) of this section for the control period starting on the later of January 1, 2014 or the deadline for meeting the unit’s monitor certification requirements under § 97.430(b) and for each control period
thereafter.

(4) Vintage of deducted allowances . A

TR NO X Annual allowance shall not be deducted, for compliance with the requirements under paragraphs (c)(1) and (2) of this section, for a control period in a calendar year before the year
for which the TR NO X Annual
allowance was allocated. (5) Allowance Management System requirements . Each TR NO X Annual allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with this subpart.

(6) Limited authorization . (i) A TR

NO X Annual allowance is a limited
authorization to emit one ton of NO X in
accordance with the TR NO X Annual Trading Program.

(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to
terminate or limit such authorization to
the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean

Air Act.

(7) Property right . A TR NO X Annual allowance does not constitute a property right.

(d) Title V Permit requirements . (1) No title V permit revision shall be required for any allocation, holding, deduction,
or transfer of TR NO X Annual
allowances in accordance with this subpart.

(2) A description of whether a unit is required to monitor and report NO X emissions using a continuous emission monitoring system (under subpart H of part 75 of this chapter), an excepted monitoring system (under appendices D and E to part 75 of this chapter), a low mass emissions excepted monitoring methodology (under § 75.19 of this chapter), or an alternative monitoring system (under subpart E of part 75 of this chapter) in accordance with §§ 97.430 through 97.435 may be added to, or changed in, a title V permit using minor permit modification procedures in accordance with §§ 70.7(e)(2) and 71.7(e)(1) of this chapter, provided that the requirements applicable to the described monitoring and reporting (as added or changed, respectively) are already incorporated in such permit. This paragraph explicitly provides that the addition of, or change to, a unit’s description as described in the prior sentence is eligible for minor permit modification procedures in accordance with §§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.

(e) Additional recordkeeping and reporting requirements . (1) Unless otherwise provided, the owners and operators of each TR NO X Annual
source and each TR NO X Annual unit at the source shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a period of 5 years from the date the document is created. This period may be extended for cause, at any time


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before the end of 5 years, in writing by
the Administrator.

(i) The certificate of representation under § 97.416 for the designated representative for the source and each

TR NO X Annual unit at the source and
all documents that demonstrate the
truth of the statements in the certificate of representation; provided that the
certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of
the submission of a new certificate of representation under § 97.416 changing the designated representative.

(ii) All emissions monitoring information, in accordance with this subpart.

(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR NO X Annual Trading Program, including any monitoring plans and monitoring system certification and recertification applications.

(2) The designated representative of a

TR NO X Annual source and each TR

NO X Annual unit at the source shall make all submissions required under
the TR NO X Annual Trading Program, including any submissions required for compliance with the TR NO X Annual assurance provisions. This requirement does not change, create an exemption from, or or otherwise affect the responsible official submission requirements under a title V operating permit program in parts 70 and 71 of this chapter.

(f) Liability . (1) Any provision of the

TR NO X Annual Trading Program that applies to a TR NO X Annual source or the designated representative of a TR

NO X Annual source shall also apply to the owners and operators of such source
and of the TR NO X Annual units at the

source.

(2) Any provision of the TR NO X Annual Trading Program that applies to

a TR NO X Annual unit or the designated representative of a TR NO X Annual unit shall also apply to the owners and operators of such unit.

(g) Effect on other authorities . No provision of the TR NO X Annual Trading Program or exemption under § 97.405 shall be construed as exempting or excluding the owners and operators, and the designated representative, of a TR NO X Annual

source or TR NO X Annual unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

**§ 97.407 Computation of time.**

(a) Unless otherwise stated, any time period scheduled, under the TR NO X Annual Trading Program, to begin on

the occurrence of an act or event shall begin on the day the act or event occurs.

(b) Unless otherwise stated, any time period scheduled, under the TR NO X Annual Trading Program, to begin

before the occurrence of an act or event shall be computed so that the period ends the day before the act or event

occurs.

(c) Unless otherwise stated, if the final day of any time period, under the TR

NO X Annual Trading Program, falls on a weekend or a State or Federal holiday, the time period shall be extended to the next business day.

**§ 97.408 Administrative appeal procedures.** 

The administrative appeal procedures

for decisions of the Administrator under

the TR NO X Annual Trading Program are set forth in part 78 of this chapter.

**§ 97.409 [Reserved]**

**§ 97.410 State NO** X **Annual trading budgets, new-unit set-asides, and variability** 

**limits.**

(a) The State NO X Annual trading budgets and new-unit set-asides for

allocations of TR NO X Annual allowances for the control periods in

2012 and thereafter are as follows:

State NO X annual trading budget (tons) * New-unit set-aside

(tons)

For 2012 and

thereafter For 2012 and thereafter

Alabama ........................................................................................................................ ........................................... 69,169 2,075
Connecticut .................................................................................................................... .......................................... 2,775 83
Delaware ....................................................................................................................... ........................................... 6,206 186
District of Columbia ........................................................................................................... ...................................... 170 5
Florida ........................................................................................................................ .............................................. 120,001 3,600 Georgia ........................................................................................................................ ............................................ 73,801 2,214
Illinois ....................................................................................................................... ................................................ 56,040 1,681
Indiana ........................................................................................................................ ............................................. 115,687 3,471
Iowa ........................................................................................................................... .............................................. 46,068 1,382
Kansas ......................................................................................................................... ............................................ 51,321 1,540 Kentucky ....................................................................................................................... ........................................... 74,117 2,224
Louisiana ...................................................................................................................... ............................................ 43,946 1,318 Maryland ....................................................................................................................... ........................................... 17,044 511
Massachusetts .................................................................................................................. ....................................... 5,960 179 Michigan ....................................................................................................................... ............................................ 64,932 1,948
Minnesota ...................................................................................................................... .......................................... 41,322 1,240
Missouri ....................................................................................................................... ............................................. 57,681 1,730
Nebraska ....................................................................................................................... ........................................... 43,228 1,297 New Jersey ..................................................................................................................... ......................................... 11,826 355
New York ....................................................................................................................... .......................................... 23,341 700
North Carolina ................................................................................................................. ......................................... 51,800 1,554
Ohio ........................................................................................................................... .............................................. 97,313 2,919 Pennsylvania ................................................................................................................... ......................................... 113,903 3,417
South Carolina ................................................................................................................. ........................................ 33,882 1,016
Tennessee ...................................................................................................................... ......................................... 28,362 851 Virginia ....................................................................................................................... .............................................. 29,581 887 West Virginia .................................................................................................................. .......................................... 51,990 1,560
Wisconsin ...................................................................................................................... ........................................... 44,846 1,345


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State NO X annual trading budget (tons) * New-unit set-aside

(tons)

For 2012 and

thereafter For 2012 and thereafter

Total .......................................................................................................................... ........................................ 1,376,312 41,288

* Without variability limits.

(b) The States’ one-year and three-year variability limits for the State NO X Annual trading budgets for the control periods in 2014 and thereafter are as

follows:

State One-year variability

limits Three-year variability

limits

2014 and thereafter

(tons) 2016 and thereafter

(tons)

Alabama ........................................................................................................................ ........................................... 6,917 3,993
Connecticut .................................................................................................................... .......................................... 5,000 2,887
Delaware ....................................................................................................................... ........................................... 5,000 2,887
District of Columbia ........................................................................................................... ...................................... 5,000 2,887
Florida ........................................................................................................................ .............................................. 12,000 6,928 Georgia ........................................................................................................................ ............................................ 7,380 4,261
Illinois ....................................................................................................................... ................................................ 5,604 3,235
Indiana ........................................................................................................................ ............................................. 11,569 6,679
Iowa ........................................................................................................................... .............................................. 5,000 2,887
Kansas ......................................................................................................................... ............................................ 5,132 2,963 Kentucky ....................................................................................................................... ........................................... 7,412 4,279
Louisiana ...................................................................................................................... ............................................ 5,000 2,887 Maryland ....................................................................................................................... ........................................... 5,000 2,887
Massachusetts .................................................................................................................. ....................................... 5,000 2,887 Michigan ....................................................................................................................... ............................................ 6,493 3,749
Minnesota ...................................................................................................................... .......................................... 5,000 2,887
Missouri ....................................................................................................................... ............................................. 5,768 3,330
Nebraska ....................................................................................................................... ........................................... 5,000 2,887 New Jersey ..................................................................................................................... ......................................... 5,000 2,887
New York ....................................................................................................................... .......................................... 5,000 2,887
North Carolina ................................................................................................................. ......................................... 5,180 2,991
Ohio ........................................................................................................................... .............................................. 9,731 5,618 Pennsylvania ................................................................................................................... ......................................... 11,390 6,576
South Carolina ................................................................................................................. ........................................ 5,000 2,887
Tennessee ...................................................................................................................... ......................................... 5,000 2,887 Virginia ....................................................................................................................... .............................................. 5,000 2,887 West Virginia .................................................................................................................. .......................................... 5,199 3,002
Wisconsin ...................................................................................................................... ........................................... 5,000 2,887

**§ 97.411 Timing requirements for TR NO** X **Annual allowance allocations.**

(a) Existing units. (1) TR NO X Annual allowances are allocated, for the control periods in 2012 and each year thereafter, as set forth in appendix A to this subpart. Listing a unit in such appendix does not constitute a
determination that the unit is a TR NO X Annual unit, and not listing a unit in such appendix does not constitute a
determination that the unit is not a TR

NO X Annual unit.

(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being
allocated TR NO X Annual allowances does not operate, starting after 2011, during the control period in three consecutive years, such unit will not be allocated the TR NO X Annual allowances set forth in appendix A to this subpart for the unit for the control periods in the seventh year after the first such year and in each year after that seventh year. All TR NO X Annual
allowances that would otherwise have
been allocated to such unit will be
allocated to the new unit set-aside for the respective years involved. If such unit resumes operation, the
Administrator will allocate TR NO X Annual allowances to the unit in accordance with paragraph (b) of this

section.

(b) New units. (1) By July 1, 2012 and July 1 of each year thereafter, the
Administrator will calculate the TR

NO X Annual allowance allocation for
each TR NO X Annual unit, in accordance with § 97.412, for the control period in the year of the applicable calculation deadline under this paragraph and will promulgate a notice of availability of the results of the
calculations.

(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced
in such notice.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations are in accordance with § 97.412 and §§ 97.406(b)(2) and 97.430 through

97.435.


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(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By September 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(c) Units that are not TR NO X Annual

units. For each control period in 2012 and thereafter, if the Administrator
determines that TR NO X Annual
allowances were allocated under paragraph (a) of this section for the control period to a recipient that is not actually a TR NO X Annual unit under § 97.404 as of January 1, 2012 or whose deadline for meeting monitor certification requirements under § 97.430(b)(1) and (2) is after January 1,
2012 or if the Administrator determines
that TR NO X Annual allowances were allocated under paragraph (b) of this section and § 97.412 for the control period to a recipient that is not actually

a TR NO X Annual unit under § 97.404 as of January 1 of the control period, then the Administrator will notify the designated representative and will act in accordance with the following procedures:

(1) Except as provided in paragraph (c)(2) or (3) of this section, the
Administrator will not record such TR

NO X Annual allowances under § 97.421.

(2) If the Administrator already
recorded such TR NO X Annual allowances under § 97.421 and if the
Administrator makes such determination before making deductions
for the source that includes such recipient under § 97.424(b) for such control period, then the Administrator
will deduct from the account in which
such TR NO X Annual allowances were
recorded an amount of TR NO X Annual
allowances allocated for the same or a prior control period equal to the amount of such already recorded TR NO X Annual allowances. The authorized account representative shall ensure that
there are sufficient TR NO X Annual
allowances in such account for completion of the deduction.

(3) If the Administrator already
recorded such TR NO X Annual allowances under § 97.421 and if the
Administrator makes such determination after making deductions
for the source that includes such recipient under § 97.424(b) for such control period, then the Administrator will not make any deduction to take account of such already recorded TR

NO X Annual allowances.

(4) The Administrator will transfer the

TR NO X Annual allowances that are not recorded, or that are deducted, in accordance with paragraphs (c)(1) and(2) of this section to the new unit setaside, for the State in which such recipient is located, for the control period in the year of such transfer if the notice required in paragraph (b)(1) of this section for the control period in that year has not been promulgated or, if such notice has been promulgated, in the next year.

**§ 97.412 TR NO** X **Annual allowance**
**allocations for new units.**

(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR NO X Annual
allowances to TR NO X Annual units in a State that are not listed in appendix A to this subpart, to TR NO X Annual
units that are so listed and whose
allocation of NO X Annual allowances for such control period is covered by § 97.411(c)(1) or (2), and to TR NO X Annual units that are so listed and, pursuant to § 97.411(a)(2), are not
allocated TR NO X Annual allowances for such control period but operate during the immediately preceding control period:

(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be
allocated TR NO X Annual allowances in an amount equal to the applicable
amount of tons of NO X emissions as setforth in § 97.410(a). Each new unit setaside will be allocated additional TR

NO X Annual allowances in accordance with § 97.411(a)(2) and (c)(4).

(2) The designated representative of
such TR NO X Annual unit may submit to the Administrator a request, in a format prescribed by the Administrator,
to be allocated TR NO X Annual allowances for a control period, starting with the later of the control period in 2012, the first control period after the control period in which the TR NO X Annual unit commences commercial operation (for a unit not listed in appendix A to this subpart), or the first control period after the control period in which the unit resumes operation (for a unit listed in appendix A of this subpart) and for each subsequent control period.

(i) The request must be submitted on or before May 1 of the first control period for which TR NO X Annual allowances are sought and after the date
on which the TR NO X Annual unit commences commercial operation (for a unit not listed in appendix A of this subpart) or on which the unit resumes operation (for a unit listed in appendix A of this subpart).

(ii) For each control period for which an allocation is sought, the request must
be for TR NO X Annual allowances in an amount equal to the unit’s total tons of

NO X emissions during the immediately preceding control period.

(3) The Administrator will review
each TR NO X Annual allowance allocation request under paragraph (a)(2) of this section and will accept the request only if it meets the requirements of paragraph (a)(2) of this section. The
Administrator will allocate TR NO X Annual allowances for each control period pursuant to an accepted request
as follows:

(i) After May 1 of such control period,
the Administrator will determine the
sum of the TR NO X Annual allowances requested in all accepted allowance allocation requests for such control period.

(ii) If the amount of TR NO X Annual
allowances in the new unit set-aside for such control period is greater than or equal to the sum under paragraph (a)(3)(i) of this section, then the
Administrator will allocate the amount
of TR NO X Annual allowances requested to each TR NO X Annual unit covered by an accepted allowance allocation request.

(iii) If the amount of TR NO X Annual
allowances in the new unit set-aside for such control period is less than the sum under paragraph (a)(3)(i) of this section,
then the Administrator will allocate to
each TR NO X Annual unit covered by an accepted allowance allocation request
the amount of the TR NO X Annual allowances requested, multiplied by the
amount of TR NO X Annual allowances
in the new unit set-aside for such control period, divided by the sum determined under paragraph (a)(3)(i) of this section, and rounded to the nearest
allowance.

(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.411(b), each designated representative that submitted an allowance allocation request of the
amount of TR NO X Annual allowances (if any) allocated for such control period
to the TR NO X Annual unit covered by the request.

(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any
unallocated TR NO X Annual allowances
remain in the new unit set-aside under paragraph (a) of this section for a State for such control period, the
Administrator will allocate to each TR


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NO X Annual unit that is in the State, is listed in appendix A to this subpart, and
continues to be allocated TR NO X Annual allowances for such control period in accordance with § 97.411(a)(2), an amount of TR NO X Annual allowances equal to the following: The total amount of such remaining unallocated TR NO X Annual allowances in such new unit set-aside, multiplied by the unit’s allocation under § 97.411(a) for such control period, divided by the remainder of the amount of tons in the applicable State

NO X Annual trading budget minus the
amount of tons in such new unit setaside, and rounded to the nearest
allowance.

**§ 97.413 Authorization of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.415,
each TR NO X Annual source, including
all TR NO X Annual units at the source, shall have one and only one designated representative, with regard to all matters
under the TR NO X Annual Trading Program.

(1) The designated representative shall be selected by an agreement binding on the owners and operators of
the source and all TR NO X Annual units
at the source and shall act in accordance
with the certification statement in § 97.416(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.416:

(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source
and each TR NO X Annual unit at the source in all matters pertaining to the

TR NO X Annual Trading Program, notwithstanding any agreement between the designated representative and such owners and operators; and

(ii) The owners and operators of the
source and each TR NO X Annual unit at the source shall be bound by any
decision or order issued to the designated representative by the Administrator regarding the source or any such unit.

(b) Except as provided under § 97.415,
each TR NO X Annual source may have one and only one alternate designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative. (1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR NO X Annual units at the source and shall act
in accordance with the certification statement in § 97.416(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.416:

(i) The alternate designated representative shall be authorized;

(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and

(iii) The owners and operators of the
source and each TR NO X Annual unit at the source shall be bound by any
decision or order issued to the alternate designated representative by the Administrator regarding the source or any such unit.

(c) Except in this section, § 97.402, and §§ 97.414 through 97.418, whenever
the term ‘‘ designated representative ’’ is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.

**§ 97.414 Responsibilities of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.418 concerning delegation of authority to make submissions, each submission
under the TR NO X Annual Trading Program shall be made, signed, and certified by the designated representative or alternate designated representative for each TR NO X Annual
source and TR NO X Annual unit for
which the submission is made. Each
such submission shall include the following certification statement by the designated representative or alternate designated representative: ‘‘ I am
authorized to make this submission on behalf of the owners and operators of
the source or units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the
statements and information submitted
in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(b) The Administrator will accept or
act on a submission made for a TR NO X Annual source or a TR NO X Annual unit only if the submission has been made, signed, and certified in accordance with paragraph (a) of this section and § 97.418.

**§ 97.415 Changing designated representative and alternate designated**  **representative; changes in owners and operators.** 

(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.416. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date
when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the TR NO X Annual source
and the TR NO X Annual units at the

source.

(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.416. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the
time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the TR NO X Annual source and the TR NO X Annual
units at the source.

(c) Changes in owners and operators. (1) In the event an owner or operator of

a TR NO X Annual source or a TR NO X Annual unit is not included in the list of owners and operators in the certificate of representation under § 97.416, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the source or unit, and the decisions and orders of the Administrator, as if the owner or operator were included in such list.

(2) Within 30 days after any change in the owners and operators of a TR NO X Annual source or a TR NO X Annual unit, including the addition of a new


### 45379 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

owner or operator, the designated representative or any alternate designated representative shall submit a
revision to the certificate of representation under § 97.416 amending the list of owners and operators to include the change.

**§ 97.416 Certificate of representation.**

(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:

(1) Identification of the TR NO X Annual source, and each TR NO X Annual unit at the source, for which the certificate of representation is submitted, including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type, identification number and nameplate capacity (in MWe rounded to the nearest tenth) of each generator served by each such unit, and actual or projected date of commencement of commercial operation.

(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

(3) A list of the owners and operators
of the TR NO X Annual source and of
each TR NO X Annual unit at the source.

(4) The following certification statements by the designated representative and any alternate designated representative—

(i) ‘‘ I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR

NO X Annual unit at the source. ’’

(ii) ‘‘ I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR

NO X Annual Trading Program on behalf of the owners and operators of the
source and of each TR NO X Annual unit
at the source and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions and by any order issued to me by the Administrator regarding the

source or unit. ’’

(iii) ‘‘ Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR NO X Annual unit, or where a utility or industrial customer purchases power from a TR

NO X Annual unit under a life-of-theunit, firm power contractual arrangement, I certify that: I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of each TR

NO X Annual unit at the source; and TR

NO X Annual allowances and proceeds of transactions involving TR NO X Annual allowances will be deemed to be held or distributed in proportion to each holder’s legal, equitable, leasehold, or contractual reservation or entitlement, except that, if such multiple holders have expressly provided for a different
distribution of TR NO X Annual allowances by contract, TR NO X Annual allowances and proceeds of transactions involving TR NO X Annual allowances
will be deemed to be held or distributed
in accordance with the contract. ’’

(5) The signature of the designated representative and any alternate designated representative and the dates signed.

(b) Unless otherwise required by the Administrator, documents of agreement
referred to in the certificate of representation shall not be submitted to
the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

**§ 97.417 Objections concerning designated representative and alternate**  **designated representative.**

(a) Once a complete certificate of representation under § 97.416 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.416 is received by the Administrator.

(b) Except as provided in § 97.415(a) or (b), no objection or other
communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator
under the TR NO X Annual Trading Program.

(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR

NO X Annual allowance transfers. **§ 97.418 Delegation by designated representative and alternate designated**  **representative.**

(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(c) In order to delegate authority to
make an electronic submission to the
Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;

(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an

‘‘ agent ’’ );

(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and

(4) The following certification statements by such designated representative or alternate designated representative:

(i) ‘‘ I agree that any electronic
submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.418(d) shall be deemed to be an electronic submission by me. ’’

(ii) ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.418(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me
under 40 CFR 97.418 is terminated. ’’

(d) A notice of delegation submitted under paragraph (c) of this section shall


### 45380 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(e) Any electronic submission covered by the certification in paragraph (c)(4)(i)
of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall
be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.

**§ 97.419 [Reserved]**

**§ 97.420 Establishment of Allowance Management System accounts.** 

(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.416, the
Administrator will establish a compliance account for the TR NO X Annual source for which the certificate of representation was submitted, unless the source already has a compliance account. The designated representative and any alternate designated representative of the source shall be the authorized account representative and
the alternate authorized account representative respectively of the compliance account.

(b) General accounts —(1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring TR NO X Annual allowances, by submitting to the Administrator a complete application for a general account. Such application shall designate one and only one authorized account representative and may designate one and only one
alternate authorized account representative who may act on behalf of the authorized account representative.

(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR NO X Annual allowances held in the general account.

(B) The agreement by which the
alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act
in lieu of the authorized account representative.

(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:

(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;

(B) An identifying name for the general account;

(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the TR NO X Annual allowances held in the general account;

(D) The following certification statement by the authorized account representative and any alternate authorized account representative: ‘‘ I certify that I was selected as the authorized account representative or the
alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR NO X Annual allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities
under the TR NO X Annual Trading Program on behalf of such persons and that each such person shall be fully bound by my representations, actions, inactions, or submissions and by any order or decision issued to me by the Administrator regarding the general

account. ’’

(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.

(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted
to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator: (A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to TR NO X Annual allowances held in the general account in all matters pertaining to the TR NO X Annual Trading Program, notwithstanding any agreement between the authorized account representative and such person.

(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.

(C) Each person who has an ownership interest with respect to TR

NO X Annual allowances held in the general account shall be bound by any
order or decision issued to the authorized account representative or
alternate authorized account representative by the Administrator regarding the general account.

(ii) Except as provided in paragraph (b)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to TR

NO X Annual allowances held in the general account. Each such submission shall include the following certification statement by the authorized account representative or any alternate authorized account representative: ‘‘ I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the

TR NO X Annual allowances held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements
and information submitted in this
document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(iii) Except in this section, whenever
the term ‘‘ authorized account representative ’’ is used in this subpart,
the term shall be construed to include the authorized account representative or


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any alternate authorized account representative.

(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the TR NO X Annual allowances in the general account.

(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new
alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the

TR NO X Annual allowances in the general account.

(iii)(A) In the event a person having an ownership interest with respect to

TR NO X Annual allowances in the general account is not included in the list of such persons in the application for a general account, such person shall be deemed to be subject to and bound by the application for a general account, the representation, actions, inactions,
and submissions of the authorized account representative and any alternate authorized account representative of the account, and the decisions and orders of the Administrator, as if the person were
included in such list.

(B) Within 30 days after any change in the persons having an ownership interest with respect to NO X Annual allowances in the general account, including the addition of a new person, the authorized account representative or any alternate authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the TR NO X Annual allowances in the general account to include the change.

(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (b)(1)
of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the
Administrator.

(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication
submitted to the Administrator concerning the authorization, or any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the
Administrator under the TR NO X Annual Trading Program.

(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR

NO X Annual allowance transfers.

(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(iii) In order to delegate authority to
make an electronic submission to the
Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or
alternate authorized account representative, as appropriate, must
submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements: (A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any)
of such authorized account representative or alternate authorized account representative;

(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to

as an ‘‘ agent ’’ );

(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;

(D) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ I agree that any
electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is
made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.420(b)(5)(iv) shall be deemed to be an electronic submission by me. ’’ ; and

(E) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.420(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.420(b)(5) is terminated. ’’

.

(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or
alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or
alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of
this section shall be deemed to be an electronic submission by the designated


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representative or alternate designated representative submitting such notice of delegation.

(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR NO X Annual allowance transfer under § 97.422 for any TR NO X Annual allowances in the
account to one or more other Allowance Management System accounts.

(ii) If a general account has no TR

NO X Annual allowance transfers to or from the account for a 12-month period or longer and does not contain any TR

NO X Annual allowances, the Administrator may notify the authorized account representative for the account
that the account will be closed after 20 business days after the notice is sent.
The account will be closed after the 20- day period unless, before the end of the 20-day period, the Administrator receives a correctly submitted TR NO X Annual allowance transfer under § 97.422 to the account or a statement submitted by the authorized account representative or alternate authorized account representative demonstrating to
the satisfaction of the Administrator good cause as to why the account
should not be closed.

(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of
this section.

(d) Responsibilities of authorized account representative and alternate authorized account representative. After
the establishment of an Allowance Management System account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction
or transfer of TR NO X Annual allowances in the account, only if the submission has been made, signed, and certified in accordance with §§ 97.414(a) and 97.418 or paragraphs (b)(2)(ii) and (b)(5) of this section.

**§ 97.421 Recordation of TR NO** X **Annual**
**allowance allocations.**

(a) By September 1, 2011, the
Administrator will record in each TR

NO X Annual source’s compliance
account the TR NO X Annual allowances
allocated for the TR NO X Annual units
at the source in accordance with §§ 97.411(a) for the control periods in 2012, 2013, and 2014.

(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will
record in each TR NO X Annual source’s compliance account the TR NO X Annual
allowances allocated for the TR NO X Annual units at the source in accordance with § 97.411(a) for the control period in the third year after the year of the applicable recordation deadline under this paragraph.

(c) By September 1, 2012 and September 1 of each year thereafter, the
Administrator will record in each TR

NO X Annual source’s compliance
account the TR NO X Annual allowances
allocated for the TR NO X Annual units
at the source in accordance with § 97.412 for the control period in the year of the applicable recordation deadline under this paragraph.

(d) When recording the allocation of

TR NO X Annual allowances for a TR

NO X Annual unit in a compliance account, the Administrator will assign
each TR NO X Annual allowance a unique identification number that will include digits identifying the year of the control period for which the TR NO X Annual allowance is allocated.

**§ 97.422 Submission of TR NO** X **Annual**
**allowance transfers.**

(a) An authorized account representative seeking recordation of a

TR NO X Annual allowance transfer shall
submit the transfer to the Administrator.

(b) A TR NO X Annual allowance transfer shall be correctly submitted if:

(1) The transfer includes the following elements, in a format prescribed by the
Administrator:

(i) The account numbers established by the Administrator for both the transferor and transferee accounts;

(ii) The serial number of each TR NO X Annual allowance that is in the
transferor account and is to be transferred; and

(iii) The name and signature of the authorized account representative of the transferor account and the date signed;
and

(2) When the Administrator attempts to record the transfer, the transferor
account includes each TR NO X Annual allowance identified by serial number in
the transfer.

**§ 97.423 Recordation of TR NO** X **Annual**
**allowance transfers.**

(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR NO X Annual allowance transfer, the Administrator
will record a TR NO X Annual allowance transfer by moving each TR NO X Annual allowance from the transferor
account to the transferee account as specified by the request, provided that the transfer is correctly submitted under § 97.422.

(b)(1) A TR NO X Annual allowance
transfer that is submitted for recordation after the allowance transfer deadline for a control period and that includes any

TR NO X Annual allowances allocated for any control period before such
allowance transfer deadline will not be
recorded until after the Administrator completes the deductions under § 97.424 for the control period immediately before such allowance
transfer deadline.

(2) A TR NO X Annual allowance
transfer that is submitted for recordation after the deadline for holding TR NO X Annual allowances described in § 97.425(b)(5) and that includes any TR

NO X Annual allowances allocated for a control period before the year of such
deadline will not be recorded until after the Administrator completes the deductions under § 97.425 for the control period immediately before the year of such deadline.

(c) Where a TR NO X Annual allowance transfer is not correctly submitted under § 97.422, the
Administrator will not record such
transfer.

(d) Within 5 business days of
recordation of a TR NO X Annual allowance transfer under paragraphs (a) and (b) of the section, the Administrator will notify the authorized account representatives of both the transferor
and transferee accounts.

(e) Within 10 business days of receipt
of a TR NO X Annual allowance transfer that is not correctly submitted under § 97.422, the Administrator will notify the authorized account representatives of both accounts subject to the transfer
of:

(1) A decision not to record the transfer, and

(2) The reasons for such nonrecordation.

**§ 97.424 Compliance with TR NO** X **Annual**
**emissions limitation.**

(a) Availability for deduction for compliance. TR NO X Annual
allowances are available to be deducted for compliance with a source’s TR NO X Annual emissions limitation for a control period in a given year only if the

TR NO X Annual allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in the source’s compliance account as of the allowance
transfer deadline for such control period.

(b) Deductions for compliance. After the recordation, in accordance with § 97.423, of TR NO X Annual allowance transfers submitted by the allowance transfer deadline for a control period,
the Administrator will deduct from the compliance account TR NO X Annual allowances available under paragraph


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(a) of this section in order to determine
whether the source meets the TR NO X Annual emissions limitation for such control period, as follows:

(1) Until the amount of TR NO X Annual allowances deducted equals the
number of tons of total NO X emissions
from all TR NO X Annual units at the source for such control period; or

(2) If there are insufficient TR NO X Annual allowances to complete the deductions in paragraph (b)(1) of this section, until no more TR NO X Annual allowances available under paragraph (a) of this section remain in the compliance account.

(c)(1) Identification of TR NO X Annual allowances by serial number. The authorized account representative for a source’s compliance account may request that specific TR NO X Annual allowances, identified by serial number, in the compliance account be deducted
for emissions or excess emissions for a control period in accordance with paragraph (b) or (d) of this section. In order to be complete, such request shall be submitted to the Administrator by
the allowance transfer deadline for such control period and include, in a format prescribed by the Administrator, the
identification of the TR NO X Annual source and the appropriate serial
numbers.

(2) First-in, first-out. The
Administrator will deduct TR NO X Annual allowances under paragraph (b) or (d) of this section from the source’s compliance account in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the case of
identification of an insufficient amount
of TR NO X Annual allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following order:

(i) Any TR NO X Annual allowances
that were allocated to the units at the
source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR NO X Annual allowances that were allocated to any unit and
transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in
which the TR NO X Annual source has excess emissions, the Administrator will deduct from the source’s compliance
account an amount of TR NO X Annual allowances, allocated for the control period in the immediately following year, equal to two times the number of
tons of the source’s excess emissions. (e) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraphs (b) and (d) of this section.

**§ 97.425 Compliance with TR NO** X **Annual assurance provisions.** 

(a) Availability for deduction. TR NO X Annual allowances are available to be deducted for compliance with the TR

NO X Annual assurance provisions for a control period in a given year by an
owner of one or more TR NO X Annual units in a State only if the TR NO X Annual allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in a compliance account, designated by the owner in accordance with paragraph (b)(4)(ii) of this section,
of one of the owner’s TR NO X Annual
sources in the State as of the deadline established in paragraph (b)(5) of this

section.

(b) Deductions for compliance. The
Administrator will deduct TR NO X Annual allowances available under paragraph (a) of this section for compliance with the TR NO X Annual assurance provisions for a State for a control period in a given year in accordance with the following procedures:

(1) By June 1, 2015 and June 1 of each year thereafter, the Administrator will:

(i) Calculate, separately for each State,
the total amount of NO X emissions from
all TR NO X Annual units in the State during the control period in the year before the year of this calculation deadline and the amount, if any, by
which such total amount of NO X emissions exceeds the State assurance level as described in § 97.406(c)(2)(iii);
and

(ii) Promulgate a notice of availability
of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations
of the NO X emissions for each TR NO X Annual unit and of the amounts described in §§ 97.406(c)(2)(iii)(A) and (B) for each State.

(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of
this section.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each TR

NO X Annual unit and each State for the control period in the year involved are in accordance with § 97.406(c)(2)(iii) and §§ 97.406(b) and 97.430 through

97.435. (ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By August 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR NO X Annual
sources with total NO X emissions exceeding the State assurance level for a control period, as described in § 97.406(c)(2)(iii):

(i) By August 15 immediately after the promulgation of such notice, the designated representative of each TR

NO X Annual source in each such State shall submit a statement, in a format prescribed by the Administrator:

(A) Listing all the owners of each TR

NO X Annual unit at the source, explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of

‘‘ owner ’’ in § 97.402, and listing, separately for each unit, the percentage of the legal, equitable, leasehold, or
contractual reservation or entitlement for each such owner as of midnight of December 31 of the control period in the year involved; and

(B) For each TR NO X Annual unit at the source that operates during, but is
allocated no TR NO X Annual allowances for, the control period in the year involved, identifying whether the unit is a coal-fired boiler, simple combustion turbine, or combined cycle turbine cycle and providing the unit’s
allowable NO X emission rate for such control period.

(ii) By September 15 immediately after the promulgation of such notice, the Administrator will calculate, for
each such State and each owner of one

or more TR NO X Annual units in the State and for the control period in the year involved, each owner’s share of the
total NO X emissions from all TR NO X Annual units in the State, each owner’s assurance level, and the amount (if any)
of TR NO X Annual allowances that each
owner must hold in accordance with the calculation formula in § 97.406(c)(2)(i) and will promulgate a notice of availability of the results of these
calculations.

(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability


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required in paragraph (b)(3)(ii) of this

section.

(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each owner for the control period in the year
involved are consistent with the NO X emissions for the relevant TR NO X Annual units as set forth in the notice required in paragraph (b)(2)(ii) of this section, the definitions of ‘‘ owner ’’

,

‘‘ owner’s assurance level ’’ , and ‘‘ owner’s
share ’’ in § 97.402, and the calculation formula in § 97.406(c)(2)(i) and shall not raise any issues about any data used in the notice of data availability required in paragraph (b)(2)(ii) of this section.

(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section. By November 15 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that
the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(3)(iii)(A)
of this section.

(4) By December 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:

(i) Each owner identified, in such notice, as owning one or more TR NO X Annual units in a State and as being required to hold TR NO X Annual allowances shall designate the compliance account of one of the
sources at which such unit or units are located to hold such required TR NO X Annual allowances;

(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.

(5)(i) As of midnight of December 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount
of TR NO X Annual allowances, available for deduction under paragraph (a) of this section, equal to the amount the owner is required to hold as calculated by the Administrator and referenced in
such notice.

(ii) Notwithstanding the allowanceholding deadline specified in paragraph (b)(5)(i) of this section, if December 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day
thereafter.

(6) After December 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.423, of TR NO X Annual allowance transfers submitted by midnight of such date, the Administrator will deduct from each compliance account designated in accordance with paragraph (b)(4)(ii) of this section, TR

NO X Annual allowances available under paragraph (a) of this section, as follows:

(i) Until the amount of TR NO X Annual allowances deducted equals the amount that the owner designating the compliance account is required to hold as calculated by the Administrator and referenced in the notice required in paragraph (b)(3)(iii)(B) of this section; or

(ii) If there are insufficient TR NO X Annual allowances to complete the deductions in paragraph (b)(6)(i) of this section, until no more TR NO X Annual allowances available under paragraph (a) of this section remain in the compliance account.

(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice,
the amount of TR NO X Annual allowances that each owner is required
to hold in accordance with § 97.406(c)(2)(i) for the control period in the year involved shall continue to be such amount as calculated by the
Administrator and referenced in such notice required in paragraph (b)(3)(iii)(B) of this section, except as
follows:

(i) If any such data are revised by the
Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal
under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR NO X Annual allowances that owners are required to hold in
accordance with the calculation formula in § 97.406(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that— (A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and

(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section.

(ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the
Administrator will use the data as so
revised to recalculate the amounts of TR

NO X Annual allowances that owners are required to hold in accordance with the calculation formula in § 97.406(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that such litigation was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii)(B) of this section.

(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR NO X Annual allowances that an owner is required to hold for the control period in the year involved with regard to the State
involved-

(A) Where the amount of TR NO X Annual allowances that an owner is required to hold increases as a result of the use of all such revised data, the Administrator will establish a new,
reasonable deadline on which the owner
shall hold the additional amount of TR

NO X Annual allowances in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section. The owner’s failure to hold such additional amount, as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s failure to hold such additional amount, as required, as of the
new deadline shall be a violation of the
Clean Air Act. Each TR NO X Annual
allowance that the owner fails to hold as required as of the new deadline, and each day in the control period in the


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year involved, shall be a separate
violation of the Clean Air Act. After such deadline, the Administrator will make the appropriate deductions from the compliance account.

(B) For an owner for which the
amount of TR NO X Annual allowances required to be held decreases as a result of the use of all such revised data, the Administrator will record, in the compliance account that the owner designated in accordance with paragraph (b)(4)(ii) of this section, an
amount of TR NO X Annual allowances equal to the amount of the decrease to the extent such amount was previously deducted from the compliance account under paragraph (b)(6) of this section (and has not already been restored to the compliance account) for the control period in the year involved.

(C) Each TR NO X Annual allowance held and deducted under paragraph (b)(7)(iii)(A) of this section, or recorded under paragraph (b)(7)(iii)(B) of this section, as a result of recalculation of requirements under the TR NO X Annual assurance provisions for a control period in a given year must be a TR NO X Annual allowance allocated for a control period in the same or a prior

year.

(c)(1) Identification of TR NO X Annual allowances by serial number. The authorized account representative for each source’s compliance account designated in accordance with paragraph (b)(4)(ii) of this section may request that specific TR NO X Annual allowances, identified by serial number, in the compliance account be deducted in accordance with paragraph (b)(6) or (7) of this section. In order to be complete, such request shall be submitted to the Administrator by the allowance-holding deadline described in paragraph (b)(5) of this section and include, in a format prescribed by the Administrator, the identification of the compliance account and the appropriate
serial numbers.

(2) First-in, first-out. The
Administrator will deduct TR NO X Annual allowances under paragraphs (b)(6) and (7) of this section from each source’s compliance account designated under paragraph (b)(4)(ii) of this section in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the
case of identification of an insufficient
amount of TR NO X Annual allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following
order:

(i) Any TR NO X Annual allowances
that were allocated to the units at the
source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR NO X Annual allowances that were allocated to any unit and
transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraph (b) of this section.

**§ 97.426 Banking.**

(a) A TR NO X Annual allowance may
be banked for future use or transfer in a compliance account or a general account in accordance with paragraph (b) of this section.

(b) Any TR NO X Annual allowance that is held in a compliance account or a general account will remain in such
account unless and until the TR NO X Annual allowance is deducted or transferred under § 97.411(c), § 97.423, § 97.424, § 97.425, 97.427, 97.428,

97.442, or 97.443.

**§ 97.427 Account error.**

The Administrator may, at his or her
sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.

**§ 97.428 Administrator’s action on**
**submissions.**

(a) The Administrator may review and conduct independent audits concerning any submission under the TR NO X Annual Trading Program and make appropriate adjustments of the
information in the submission.

(b) The Administrator may deduct TR

NO X Annual allowances from or transfer

TR NO X Annual allowances to a source’s compliance account based on the information in a submission, as adjusted under paragraph (a)(1) of this section, and record such deductions and
transfers.

**§ 97.429 [Reserved]**

**§ 97.430 General monitoring, recordkeeping, and reporting requirements.** 

The owners and operators, and to the extent applicable, the designated representative, of a TR NO X Annual unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subpart H of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.402 and in § 72.2 of this chapter shall apply,
the terms ‘‘ affected unit, ’’ ‘‘ designated representative, ’’ and ‘‘ continuous emission monitoring system ’’ (or

‘‘ CEMS ’’ ) in part 75 of this chapter shall
be deemed to refer to the terms ‘‘ TR NO X Annual unit, ’’ ‘‘ designated representative, ’’ and ‘‘ continuous emission monitoring system ’’ (or

‘‘ CEMS ’’ ) respectively as defined in § 97.402, and the term ‘‘ newly affected

unit ’’ shall be deemed to mean ‘‘ newly
affected TR NO X Annual unit ’’ . The owner or operator of a unit that is not

a TR NO X Annual unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a TR NO X Annual unit.

(a) Requirements for installation, certification, and data accounting. The owner or operator of each TR NO X Annual unit shall:

(1) Install all monitoring systems required under this subpart for monitoring NO X mass emissions and individual unit heat input (including all systems required to monitor NO X emission rate, NO X concentration, stack gas moisture content, stack gas flow rate, CO 2 or O 2 concentration, and fuel flow rate, as applicable, in accordance with §§ 75.71 and 75.72 of this chapter);

(2) Successfully complete all certification tests required under § 97.431 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator shall meet the monitoring system certification and other requirements of paragraphs (a)(1) and (2) of this section on or before the following dates and shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.

(1) For the owner or operator of a TR

NO X Annual unit that commences commercial operation before July 1, 2011, January 1, 2012;

(2) For the owner or operator of a TR

NO X Annual unit that commences commercial operation on or after July 1, 2011, the later of the following:

(i) January 1, 2012; or (ii) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation;

(3) For the owner or operator of a TR

NO X Annual unit for which
construction of a new stack or flue or
installation of add-on NO X emission


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controls is completed after the applicable deadline under paragraph (b)(1) or (2) of this section, by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on
which emissions first exit to the atmosphere through the new stack or
flue or add-on NO X emissions controls;

(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a TR opt-in application is
submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.441(c); and

(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a TR NO X Annual opt-in unit, by the date on
which the TR NO X Annual opt-in unit
enters the TR NO X Annual Trading Program as provided in § 97.441(h).

(c) Reporting data. The owner or operator of a TR NO X Annual unit that does not meet the applicable compliance date set forth in paragraph (b) of this section for any monitoring system under paragraph (a)(1) of this section shall, for each such monitoring system, determine, record, and report maximum potential (or, as appropriate, minimum potential) values for NO X concentration, NO X emission rate, stack gas flow rate, stack gas moisture content, fuel flow rate, and any other parameters required to determine NO X mass emissions and heat input in accordance with § 75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 75 of this chapter, or section 2.5 of appendix E to part 75 of this chapter, as applicable.

(d) Prohibitions. (1) No owner or operator of a TR NO X Annual unit shall use any alternative monitoring system, alternative reference method, or any other alternative to any requirement of this subpart without having obtained prior written approval in accordance with § 97.435.

(2) No owner or operator of a TR NO X Annual unit shall operate the unit so as to discharge, or allow to be discharged,

NO X emissions to the atmosphere without accounting for all such
emissions in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(3) No owner or operator of a TR NO X Annual unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording NO X mass emissions discharged into the atmosphere or heat input, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(4) No owner or operator of a TR NO X Annual unit shall retire or permanently
discontinue use of the continuous emission monitoring system, any component thereof, or any other approved monitoring system under this subpart, except under any one of the following circumstances:

(i) During the period that the unit is covered by an exemption under § 97.405 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the
Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or

(iii) The designated representative
submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.431(d)(3)(i).

(e) Long-term cold storage. The owner or operator of a TR NO X Annual unit is subject to the applicable provisions of § 75.4(d) of this chapter concerning units in long-term cold storage.

**§ 97.431 Initial monitoring system certification and recertification procedures.** 

(a) The owner or operator of a TR NO X Annual unit shall be exempt from the initial certification requirements of this section for a monitoring system under § 97.430(a)(1) if the following conditions

are met:

(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and

(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of
this section.

(b) The recertification provisions of this section shall apply to a monitoring system under § 97.430(a)(1) that is exempt from initial certification requirements under paragraph (a) of this

section.

(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the

NO X emission rate measured in a common stack or a petition under § 75.66 of this chapter for an alternative to a requirement in § 75.12 or § 75.17 of this chapter, the designated representative shall resubmit the petition to the Administrator under § 97.435 to determine whether the approval applies under the TR NO X Annual Trading Program.

(d) Except as provided in paragraph (a) of this section, the owner or operator
of a TR NO X Annual unit shall comply with the following initial certification and recertification procedures for a continuous monitoring system ( i.e., a continuous emission monitoring system and an excepted monitoring system under appendices D and E to part 75 of this chapter) under § 97.430(a)(1). The owner or operator of a unit that qualifies to use the low mass emissions excepted monitoring methodology under § 75.19 of this chapter or that qualifies to use an alternative monitoring system under subpart E of part 75 of this chapter shall comply with the procedures in paragraph (e) or (f) of this section respectively.

(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under § 97.430(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.430(b).

In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.

(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.430(a)(1) that may significantly affect the ability of the system to accurately measure or
record NO X mass emissions or heatinput rate or to meet the qualityassurance and quality-control requirements of § 75.21 of this chapter or appendix B to part 75 of this chapter, the owner or operator shall recertify the monitoring system in accordance with § 75.20(b) of this chapter. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit’s operation that may significantly change the stack flow or concentration profile, the owner or operator shall recertify each continuous emission monitoring system whose accuracy is potentially affected by the change, in accordance with § 75.20(b) of this chapter. Examples of changes to a continuous emission monitoring system that require recertification include replacement of the analyzer, complete


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replacement of an existing continuous emission monitoring system, or change
in location or orientation of the sampling probe or site. Any fuel flowmeter system, and any excepted

NO X monitoring system under appendix E to part 75 of this chapter, under § 97.430(a)(1) are subject to the recertification requirements in § 75.20(g)(6) of this chapter.

(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.430(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words

‘‘ certification ’’ and ‘‘ initial certification ’’ are replaced by the word

‘‘ recertification ’’ and the word ‘‘ certified ’’ is replaced by with the word

‘‘ recertified ’’

.

(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office
and the Administrator written notice of the dates of certification testing, in accordance with § 97.433.

(ii) Certification application. The designated representative shall submit
to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.

(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under
the TR NO X Annual Trading Program for a period not to exceed 120 days after receipt by the Administrator of the complete certification application for the monitoring system under paragraph (d)(3)(ii) of this section. Data measured and recorded by the provisionally certified monitoring system, in accordance with the requirements of part 75 of this chapter, will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that
the Administrator does not invalidate the provisional certification by issuing a notice of disapproval within 120 days of the date of receipt of the complete certification application by the
Administrator.

(iv) Certification application approval

process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter
and is included in the certification application will be deemed certified for
use under the TR NO X Annual Trading Program.

(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter,
then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day review period specified in paragraph (d)(3) of this section shall not begin before receipt of a complete certification application.

(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).

(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of
a monitor in accordance with § 97.432(b).

(v) Procedures for loss of certification.
If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section,
then:

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

( 1 ) For a disapproved NO X emission rate ( i.e., NO X -diluent) system, the maximum potential NO X emission rate, as defined in § 72.2 of this chapter.

( 2 ) For a disapproved NO X pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of

NO X and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

( 3 ) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO 2 concentration or the minimum potential O 2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

( 4 ) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

( 5 ) For a disapproved excepted NO X monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NO X emission rate, as defined in § 72.2 of this chapter.

(B) The designated representative
shall submit a notification of
certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this

section.

(C) The owner or operator shall repeat
all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days
after the date of issuance of the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such


### 45388 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the

certification and recertification requirements in § 75.20(g) of this chapter.

(f) The designated representative of

each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.

**§ 97.432 Monitoring system out-of-control periods.** 

(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.

(b) Audit decertification. Whenever both an audit of a monitoring system

and a review of the initial certification or recertification application reveal that any monitoring system should not have

been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.431 or the applicable provisions of part 75 of this chapter, both at the time

of the initial certification or recertification application submission and at the time of the audit, the

Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit

shall be either a field audit or an audit of any information submitted to the Administrator or any permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data

from the date of issuance of the

notification of the revoked certification

status until the date and time that the owner or operator completes subsequently approved initial

certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable

initial certification or recertification procedures in § 97.431 for each disapproved monitoring system. **§ 97.433 Notifications concerning monitoring.** 

The designated representative of a TR

NO X Annual unit shall submit written
notice to the Administrator in accordance with § 75.61 of this chapter.

**§ 97.434 Recordkeeping and reporting.**

(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in paragraphs (b) through (e) of this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.414(a).

(b) Monitoring plans. The owner or operator of a TR NO X Annual unit shall comply with requirements of § 75.73(c) and (e) of this chapter.

(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all
initial certification or recertification tests required under § 97.431, including the information required under § 75.63 of this chapter.

(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:

(1) The designated representative shall report the NO X mass emissions data and heat input data for the TR NO X Annual unit, in an electronic quarterly report in a format prescribed by the Administrator, for each calendar quarter beginning with:

(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering January 1, 2012 through March 31, 2012;

(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.430(b), unless that quarter is the third or fourth quarter of 2011, in which case reporting shall commence in the quarter covering January 1, 2012 through March 31, 2012;

(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a TR opt-in application is
submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.441(c); and

(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a TR

NO X Annual opt-in unit, the calendar quarter corresponding to the date on
which the TR NO X Annual opt-in unit
enters the TR NO X Annual Trading Program as provided in § 97.441(h). (2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.

(3) For TR NO X Annual units that are also subject to the Acid Rain Program,

TR NO X Ozone Season Trading Program, TR SO 2 Group 1 Trading Program, or TR SO 2 Group 2 Trading Program, quarterly reports shall include the applicable data and information required by subparts F through H of part 75 of this chapter as applicable, in
addition to the NO X mass emission data, heat input data, and other information required by this subpart.

(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.

(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any
corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.

(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of
this section.

(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the


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unit’s emissions are correctly and fully
monitored. The certification shall state
that:

(1) The monitoring data submitted
were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and

(2) For a unit with add-on NO X emission controls and for all hours
where NO X data are substituted in accordance with § 75.34(a)(1) of this chapter, the add-on emission controls were operating within the range of parameters listed in the quality assurance/quality control program under appendix B to part 75 of this chapter and the substitute data values do not systematically underestimate

NO X emissions.

**§ 97.435 Petitions for alternatives to monitoring, recordkeeping, or reporting**  **requirements.**

(a) The designated representative of a

TR NO X Annual unit may submit a petition under § 75.66 of this chapter to the Administrator, requesting approval to apply an alternative to any requirement of §§ 97.430 through 97.434 or paragraph (5)(i) or (ii) of the
definition of ‘‘ owner’s share ’’ in § 97.402.

(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition, including, at a minimum, the following information:

(i) Identification of each unit and source covered by the petition;

(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;

(iii) A description and diagram of any equipment and procedures used in the proposed alternative;

(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the
alternative will be de minimis; and

(v) Any other relevant information that the Administrator may require.

(c) Use of an alternative to any requirement referenced in paragraph (a)
of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.

**§ 97.440 General requirements for TR NO** X **Annual opt-in units.**

(a) A TR NO X Annual opt-in unit
must be a unit that: (1) Is located in a State; (2) Is not a TR NO X Annual unit under § 97.404;

(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and

(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.

(b) A TR NO X Annual opt-in unit
shall be deemed to be a TR NO X Annual unit for purposes of applying this subpart, except for §§ 97.405, 97.411,
and 97.412.

(c) Solely for purposes of applying the requirements of §§ 97.413 through 97.418 and §§ 97.430 through 97.435, a unit for which a TR opt-in application
is submitted and not withdrawn and is not yet approved or disapproved under § 97.442 shall be deemed to be a TR

NO X Annual unit.

(d) Any TR NO X Annual opt-in unit, and any unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved under § 97.442, located at
the same source as one or more TR NO X Annual units shall have the same designated representative and alternate designated representative as such TR

NO X Annual units.

**§ 97.441 Opt-In process.**

A unit meeting the requirements for a

TR NO X Annual opt-in unit in § 97.440(a) may become a TR NO X Annual opt-in unit only if, in accordance with this section, the designated representative of the unit submits a complete TR opt-in application for the unit and the Administrator approves the application.

(a) Applying to opt in. The designated representative of the unit may submit a complete TR opt-in application for the unit at any time, except as provided under § 97.442(e). A complete TR opt-in application shall include the following elements in a format prescribed by the
Administrator:

(1) Identification of the unit and the source where the unit is located, including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, and unit identification number and type;

(2) A certification that the unit: (i) Is not a TR NO X Annual unit under § 97.404;

(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;

(iii) Vents all of its emissions to a stack; and

(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;

(3) A monitoring plan in accordance with §§ 97.430 through 97.435;

(4) A statement that the unit, if approved to become a TR NO X Annual unit under paragraph (g) of this section, may withdraw from the TR NO X Annual Trading Program only in accordance with § 97.442;

(5) A statement that the unit, if approved to become a TR NO X Annual unit under paragraph (g) of this section, is subject to, and the owners and operators of the unit must comply with, the requirements of § 97.443;

(6) A complete certificate of representation under § 97.416 consistent with § 97.440, if no designated representative has been previously designated for the source that includes the unit; and

(7) The signature of the designated representative and the date signed.

(b) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan submitted under paragraph (a)(3) of this section. The monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the NO X emission rate and heat input of the unit and all other applicable parameters are monitored and reported in accordance with §§ 97.430 through 97.435. A determination of sufficiency shall not be construed as acceptance or approval of the monitoring plan.

(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the monitoring plan is sufficient under paragraph (b) of this section, the owner or operator of the unit shall monitor and report the NO X emission rate and the heat input of the unit and all other applicable parameters, in accordance with §§ 97.430 through 97.435, starting
on the date of certification of the necessary monitoring systems under §§ 97.430 through 97.435 and continuing until the TR opt-in application submitted under paragraph (a) of this section is disapproved under this section or, if such TR opt-in application is approved, the date and
time when the unit is withdrawn from
the TR NO X Annual Trading Program in accordance with § 97.442.

(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which
the unit enters the TR NO X Annual Trading Program under paragraph (h) of this section, during which period monitoring system availability must not


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be less than 98 percent under §§ 97.430 through 97.435 and the unit must be in full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.

(2) To the extent the NO X emission rate and the heat input of the unit are monitored and reported in accordance with §§ 97.430 through 97.435 for one or more entire control periods, in addition to the control period under paragraph (c)(1)(ii) of this section, during which control periods monitoring system availability is not less than 98 percent under §§ 97.430 through 97.435 and the unit is in full compliance with any applicable State or Federal emissions or emissions-related requirements and which control periods begin not more than 3 years before the unit enters the

TR NO X Annual Trading Program under paragraph (h) of this section, such information shall be used as provided in paragraphs (e) and (f) of this section.

(d) Statement on compliance. After submitting to the Administrator all quarterly reports required for the unit under paragraph (c) of this section, the designated representative shall submit, in a format prescribed by the Administrator, to the Administrator a statement that, for the years covered by such quarterly reports, the unit was in full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.

(e) Baseline heat input. The unit’s baseline heat input shall equal:

(1) If the unit’s NO X emission rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s total heat input (in mmBtu) for such control period; or

(2) If the unit’s NO X emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, the average of the amounts of the unit’s total heat input (in mmBtu) for such control periods.

(f) Baseline NO X emission rate. The
unit’s baseline NO X emission rate shall equal:

(1) If the unit’s NO X emission rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s NO X emission rate (in lb/mmBtu) for such control period;

(2) If the unit’s NO X emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of thissection, and the unit does not have addon NO X emission controls during any such control periods, the average of the
amounts of the unit’s NO X emission rate (in lb/mmBtu) for such control periods;

or (3) If the unit’s NO X emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, and the unit has add-on NO X emission controls during any such control periods, the average of the
amounts of the unit’s NO X emission rate (in lb/mmBtu) for such control periods during which the unit has add-on NO X emission controls.

(g) Review of TR opt-in application. (1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the
Administrator determines that the designated representative shows that the unit meets the requirements for a TR

NO X Annual opt-in unit in § 97.440, the element certified in paragraph (a)(2)(iv) of this section, and the monitoring and reporting requirements of paragraph (c) of this section, the Administrator willissue a written approval of the TR optin application for the unit. The written approval will state the unit’s baseline heat input and baseline NO X emission
rate. The Administrator will thereafter establish a compliance account for the
source that includes the unit unless the source already has a compliance

account.

(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines
that the unit cannot meet the requirements for a TR NO X Annual optin unit in § 97.440, the element certified in paragraph (a)(2)(iv) of this section, or the monitoring and reporting requirements in paragraph (c) of this section, the Administrator will issue a written disapproval of the TR opt-in application for the unit.

(h) Date of entry into TR NO X Annual Trading Program. A unit for which a TR opt-in application is approved under paragraph (g)(1) of this section shall
become a TR NO X Annual opt-in unit,
and a TR NO X Annual unit, effective as of the later of January 1, 2012 or January 1 of the first control period during which such approval is issued.

**§ 97.442 Withdrawal of TR NO** X **Annual opt-in unit from TR NO**  X **Annual Trading Program.** 

A TR NO X Annual opt-in unit may
withdraw from the TR NO X Annual Trading Program only if, in accordance with this section, the designated representative of the unit submits a request to withdraw the unit and the Administrator issues a written approval of the request.

(a) Requesting withdrawal. In order to
withdraw the TR NO X Annual opt-in
unit from the TR NO X Annual Trading Program, the designated representative
of the unit shall submit to the Administrator a request to withdraw the unit effective as of midnight of December 31 of a specified calendar year, which date must be at least 4 years after December 31 of the year of the unit’s entry into the TR NO X Annual Trading Program under § 97.441(h). The request shall be in a format prescribed by the Administrator and shall be submitted no later than 90 days before the requested effective date of
withdrawal.

(b) Conditions for withdrawal. Before

a TR NO X Annual opt-in unit covered by the request to withdraw may
withdraw from the TR NO X Annual Trading Program, the following
conditions must be met:

(1) For the control period ending on
the date on which the withdrawal is to be effective, the source that includes the

TR NO X Annual opt-in unit must meet the requirement to hold TR NO X Annual allowances under §§ 97.424 and 97.425 and cannot have any excess emissions.

(2) After the requirement under paragraph (b)(1) of this section is met,
the Administrator will deduct from the compliance account of the source that
includes the TR NO X Annual opt-in unit

TR NO X Annual allowances equal in
amount to and allocated for the same or a prior control period as any TR NO X Annual allowances allocated to the TR

NO X Annual opt-in unit under § 97.444 for any control period after the date on
which the withdrawal is to be effective.
If there are no other TR NO X Annual units at the source, the Administrator will close the compliance account, and the owners and operators of the TR NO X Annual opt-in unit may submit a TR

NO X Annual allowance transfer for any remaining TR NO X Annual allowances to another Allowance Management System account in accordance with §§ 97.422 and 97.423.

(c) Approving withdrawal. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full
amount of TR NO X Annual allowances required), the Administrator will issue a written approval of the request to withdraw, which will become effective as of midnight on December 31 of the calendar year for which the withdrawal was requested. The unit covered by the request shall continue to be a TR NO X Annual opt-in unit until the effective date of the withdrawal and shall comply with all requirements under the TR NO X


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Annual Trading Program concerning any control periods for which the unit

is a TR NO X Annual opt-in unit, even if such requirements arise or must be complied with after the withdrawal
takes effect.

(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR

NO X Annual opt-in unit.

(d) Reapplication upon failure to meet conditions of withdrawal. If the Administrator disapproves the request to withdraw, the designated representative of the unit may submit another request to withdraw in accordance with paragraphs (a) and (b)
of this section.

(e) Ability to reapply to the TR NO X Annual Trading Program. Once a TR

NO X Annual opt-in unit withdraws from
the TR NO X Annual Trading Program, the designated representative may not submit another opt-in application under § 97.441 for such unit before the date that is 4 years after the date on which
the withdrawal became effective.

**§ 97.443 Change in regulatory status.**

(a) Notification. If a TR NO X Annual opt-in unit becomes a TR NO X Annual unit under § 97.404, then the designated representative of the unit shall notify the Administrator in writing of such change in the TR NO X Annual opt-in unit’s regulatory status, within 30 days of such change.

(b) Administrator’s actions. (1) If a TR

NO X Annual opt-in unit becomes a TR

NO X Annual unit under § 97.404, the Administrator will deduct, from the compliance account of the source that
includes the TR NO X Annual opt-in unit
that becomes a TR NO X Annual unit under § 97.404, TR NO X Annual allowances equal in amount to and allocated for the same or a prior control period as:

(i) Any TR NO X Annual allowances
allocated to the TR NO X Annual opt-in unit under § 97.444 for any control period starting after the date on which
the TR NO X Annual opt-in unit becomes

a TR NO X Annual unit under § 97.404;
and

(ii) If the date on which the TR NO X Annual opt-in unit becomes a TR NO X Annual unit under § 97.404 is not December 31, the TR NO X Annual
allowances allocated to the TR NO X Annual opt-in unit under § 97.444 for the control period that includes the date
on which the TR NO X Annual opt-in
unit becomes a TR NO X Annual unit under § 97.404— (A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

NO X Annual opt-in unit becomes a TR

NO X Annual unit under § 97.404, divided by the total number of days in the control period, and

(B) Rounded to the nearest allowance. (2) The designated representative shall ensure that the compliance
account of the source that includes the

TR NO X Annual opt-in unit that
becomes a TR NO X Annual unit under § 97.404 contains the TR NO X Annual allowances necessary for completion of the deduction under paragraph (b)(1) of
this section.

(3)(i) For control periods starting after
the date on which the TR NO X Annual opt-in unit becomes a TR NO X Annual unit under § 97.404, the TR NO X Annual opt-in unit will be allocated TR NO X Annual allowances in accordance with § 97.412.

(ii) If the date on which the TR NO X Annual opt-in unit becomes a TR NO X Annual unit under § 97.404 is not December 31, the following amount of

TR NO X Annual allowances will be
allocated to the TR NO X Annual opt-in unit (as a TR NO X Annual unit) in accordance with § 97.412 for the control period that includes the date on which
the TR NO X Annual opt-in unit becomes

a TR NO X Annual unit under § 97.404:

(A) The amount of TR NO X Annual
allowances otherwise allocated to the

TR NO X Annual opt-in unit (as a TR

NO X Annual unit) in accordance with § 97.412 for the control period;

(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

NO X Annual opt-in unit becomes a TR

NO X Annual unit under § 97.404, divided by the total number of days in the control period; and (C) Rounded to
the nearest allowance.

**§ 97.444 TR NO** X **Annual allowance**
**allocations to TR NO** X **Annual opt-in units.**

(a) Timing requirements. (1) When the TR opt-in application is approved for a unit under § 97.441(g), the
Administrator will issue TR NO X Annual allowances and allocate them to the unit for the control period in which
the unit enters the TR NO X Annual Trading Program under § 97.441(h), in accordance with paragraph (b) of this

section.

(2) By no later than October 31 of the control period after the control period in
which a TR NO X Annual opt-in unit
enters the TR NO X Annual Trading Program under § 97.441(h) and October 31 of each year thereafter, the
Administrator will issue TR NO X Annual allowances and allocate them to the TR NO X Annual opt-in unit for the control period that includes such
allocation deadline and in which the

unit is a TR NO X Annual opt-in unit, in accordance with paragraph (b) of this

section.

(b) Calculation of allocation. For each control period for which a TR NO X Annual opt-in unit is to be allocated TR

NO X Annual allowances, the
Administrator will issue and allocate TR

NO X Annual allowances in accordance with the following procedures:

(1) The heat input (in mmBtu) used for calculating the TR NO X Annual
allowance allocation will be the lesser
of:

(i) The TR NO X Annual opt-in unit’s baseline heat input determined under § 97.441(g); or

(ii) The TR NO X Annual opt-in unit’s heat input, as determined in accordance with §§ 97.430 through 97.435, for the immediately prior control period, except when the allocation is being calculated for the control period in
which the TR NO X Annual opt-in unit
enters the TR NO X Annual Trading Program under § 97.441(h).

(2) The NO X emission rate (in lb/ mmBtu) used for calculating TR NO X Annual allowance allocations will be
the lesser of:

(i) The TR NO X Annual opt-in unit’s
baseline NO X emission rate (in lb/ mmBtu) determined under § 97.441(g) and multiplied by 70 percent; or

(ii) The most stringent State or
Federal NO X emissions limitation applicable to the TR NO X Annual optin unit at any time during the control period for which TR NO X Annual
allowances are to be allocated.

(3) The Administrator will issue TR

NO X Annual allowances and allocate
them to the TR NO X Annual opt-in unit in an amount equaling the heat input under paragraph (b)(1) of this section, multiplied by the NO X emission rate under paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded to
the nearest allowance.

(c) Recordation. (1) The Administrator will record, in the compliance account
of the source that includes the TR NO X Annual opt-in unit, the TR NO X Annual
allowances allocated to the TR NO X Annual opt-in unit under paragraph (a)(1) of this section.

(2) By December 1 of the control period after the control period in which

a TR NO X Annual opt-in unit enters the

TR NO X Annual Trading Program under § 97.441(h) and December 1 of each year thereafter, the Administrator will record, in the compliance account of the
source that includes the TR NO X Annual opt-in unit, the TR NO X Annual
allowances allocated to the TR NO X


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Annual opt-in unit under paragraph (a)(2) of this section.

36. Part 97 is amended by adding subpart BBBBB to read as follows:

**Subpart BBBBB—TR NO** X **Ozone Season Trading Program** 

Sec. 97.501 Purpose.
97.502 Definitions. 97.503 Measurements, abbreviations, and

acronyms. 97.504 Applicability. 97.505 Retired unit exemption. 97.506 Standard requirements. 97.507 Computation of time. 97.508 Administrative appeal procedures. 97.509 [Reserved]

97.510 State NO X Ozone Season trading budgets, new-unit set-asides, and variability limits. 97.511 Timing requirements for TR NO X Ozone Season allowance allocations.

97.512 TR NO X Ozone Season allowance
allocations for new units. 97.513 Authorization of designated representative and alternate designated representative. 97.514 Responsibilities of designated representative and alternate designated representative. 97.515 Changing designated representative and alternate designated representative; changes in owners and operators. 97.516 Certificate of representation. 97.517 Objections concerning designated representative and alternate designated representative. 97.518 Delegation by designated representative and alternate designated representative. 97.519 [Reserved]
97.520 Establishment of Allowance Management System accounts.
97.521 Recordation of TR NO X Ozone
Season allowance allocations.
97.522 Submission of TR NO X Ozone
Season allowance transfers.
97.523 Recordation of TR NO X Ozone
Season allowance transfers. 97.524 Compliance with TR NO X Ozone
Season emissions limitation. 97.525 Compliance with TR NO X Ozone Season assurance provisions. 97.526 Banking.

97.527 Account error.
97.528 Administrator’s action on
submissions. 97.529 [Reserved] 97.530 General monitoring, recordkeeping, and reporting requirements. 97.531 Initial monitoring system
certification and recertification procedures. 97.532 Monitoring system out-of-control periods. 97.533 Notifications concerning monitoring. 97.534 Recordkeeping and reporting.
97.535 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements. 97.540 General requirements for TR NO X Ozone Season opt-in units. 97.541 Opt-in process. 97.542 Withdrawal of TR NO X Ozone Season opt-in unit from TR NO X Ozone Season Trading Program. 97.543 Change in regulatory status.

97.544 TR NO X Ozone Season allowance
allocations to TR NO X Ozone Season optin units.

**Subpart BBBBB—TR NO** X **Ozone Season Trading Program** 

**§ 97.501 Purpose.**

This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) NO X Ozone Season Trading Program, under section 110 of the Clean Air Act and § 52.37(b) of this chapter, as a means of mitigating interstate transport of fine particulates and nitrogen oxides.

**§ 97.502 Definitions.**

The terms used in this subpart shall have the meanings set forth in this
section as follows:

Acid Rain Program means a multistate SO 2 and NO X air pollution control and emission reduction program established by the Administrator under title IV of the Clean Air Act and parts 72 through 78 of this chapter.

Administrator means the
Administrator of the United States Environmental Protection Agency or the
Director of the Clean Air Markets Division (or its successor) of the United
States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.

Allocate or allocation means, with regard to TR NO X Ozone Season allowances, the determination by the
Administrator of the amount of such TR

NO X Ozone Season allowances to be initially credited to a TR NO X Ozone
Season source or a new unit set-aside.

Allowable NO X emission rate means, with regard to a unit, the NO X emission rate limit that is applicable to the unit and covers the longest averaging period not exceeding one year.

Allowance Management System means the system by which the Administrator records allocations, deductions, and transfers of TR NO X Ozone Season allowances under the TR

NO X Ozone Season Trading Program. Such allowances are allocated, held, deducted, or transferred only as whole
allowances. The Allowance Management System is a component of the CAMD Business System, which is the system used by the Administrator to
handle TR NO X Ozone Season
allowances and data related to NO X emissions.

Allowance Management System

account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, holding, transfer, or deduction of TR

NO X Ozone Season allowances.

Allowance transfer deadline means, for a control period, midnight of December 1 (if it is a business day), or midnight of the first business day thereafter (if December 1 is not a business day), immediately after such control period and is the deadline by
which a TR NO X Ozone Season
allowance transfer must be submitted
for recordation in a TR NO X Ozone Season source’s compliance account in
order to be available for use in complying with the source’s TR NO X Ozone Season emissions limitation for such control period in accordance with § 97.524.

Alternate designated representative means, for a TR NO X Ozone Season
source and each TR NO X Ozone Season unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with this subpart, to act on behalf of the designated representative in matters pertaining to the TR NO X Ozone Season Trading Program. If the TR NO X Ozone Season source is also subject to the Acid Rain Program, TR NO X Annual Trading Program, TR SO 2 Group 1 Trading Program, or TR SO 2 Group 2 Trading Program, then this natural person shall be the same natural person as the alternate designated representative as defined in § 72.2 of this chapter, § 97.402, § 97.602, or § 97.702 respectively.

Authorized account representative means, with regard to a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of TR NO X Ozone Season allowances held in the general account and, with regard to a TR NO X Ozone Season source’s compliance account, the designated representative
of the source.

Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a
continuous record of the measured parameters in the measurement units required by this subpart.

Biomass means— (1) Any organic material grown for the purpose of being converted to energy;


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(2) Any organic byproduct of agriculture that can be converted into

energy; or

(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from
other material that is nonmerchantable for other purposes, and that is;

(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct
from conversion of trees to merchantable material; or

(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.

Boiler means an enclosed fossil- or
other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other
medium.

Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

Certifying official means a natural person who is:

(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;

(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or

(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking
elected official.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.

Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.

Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

Coal-fired means combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during 1990 or any year thereafter.

Cogeneration system means an integrated group, at a source, of equipment (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 electricity through the sequential use of energy.

Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine—

(1) Operating as part of a cogeneration system; and

(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—

(i) For a topping-cycle unit, (A) Useful thermal energy not less than 5 percent of total energy output;
and

(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.

(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;

(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler;
and

(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and thecogeneration system meets on a systemwide basis the requirement in paragraph(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such requirement during that calendar year.

Combustion turbine means an enclosed device comprising:

(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from
the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and

(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.

Commence commercial operation means, with regard to a unit:

(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.505.

(i) For a unit that is a TR NO X Ozone Season unit under § 97.504 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such
date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit that is a TR NO X Ozone Season unit under § 97.504 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for
commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.505, for a unit that is not a TR

NO X Ozone Season unit under § 97.504 on the later of November 15, 1990 or the
date the unit commences commercial operation as defined in introductory text of paragraph (1) of this definition, the
unit’s date for commencement of commercial operation shall be the date
on which the unit becomes a TR NO X Ozone Season unit under § 97.504.

(i) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source),
such date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of
commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

Commence operation means, with regard to a unit:

(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit’s
combustion chamber.

(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source)


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after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be
treated as the same unit.

(3) For a unit that is replaced by a unit
at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.

Common stack means a single flue through which emissions from 2 or
more units are exhausted.

Compliance account means an Allowance Management System account, established by the
Administrator for a TR NO X Ozone Season source under this subpart, in which any TR NO X Ozone Season
allowance allocations for the TR NO X Ozone Season units at the source are recorded and in which are held any TR

NO X Ozone Season allowances available for use for a control period in complying
with the source’s TR NO X Ozone Season
emissions limitation in accordance with § 97.524 and the TR NO X Ozone Season assurance provisions in accordance with § 97.525.

Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent
record of NO X emissions, stack gas volumetric flow rate, stack gas moisture content, and O 2 or CO 2 concentration (as applicable), in a manner consistent with part 75 of this chapter and §§ 97.530 through 97.535. The following systems are the principal types of continuous emission monitoring systems:

(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A NO X concentration monitoring system, consisting of a NO X pollutant
concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of NO X emissions, in parts per million (ppm);

(3) A NO X emission rate (or NO X diluent) monitoring system, consisting
of a NO X pollutant concentration monitor, a diluent gas (CO 2 or O 2 ) monitor, and an automated data acquisition and handling system and providing a permanent, continuous
record of NO X concentration, in parts per million (ppm), diluent gas concentration, in percent CO 2 or O 2 , and

NO X emission rate, in pounds per million British thermal units (lb/ mmBtu);

(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H 2 O;

(5) A CO 2 monitoring system, consisting of a CO 2 pollutant concentration monitor (or an O 2 monitor plus suitable mathematical equations
from which the CO 2 concentration is derived) and an automated data acquisition and handling system and providing a permanent, continuous
record of CO 2 emissions, in percent CO 2 ; and

(6) An O 2 monitoring system, consisting of an O 2 concentration
monitor and an automated data acquisition and handling system and providing a permanent, continuous
record of O 2 , in percent O 2

.

Control period means the period starting May 1 of a calendar year, except as provided in § 97.506(c)(3), and ending on September 30 of the same year, inclusive.

Designated representative means, for

a TR NO X Ozone Season source and
each TR NO X Ozone Season unit at the source, the natural person who is authorized by the owners and operators
of the source and all such units at the source, in accordance with this subpart, to represent and legally bind each owner and operator in matters pertaining to the TR NO X Ozone Season Trading Program. If the TR NO X Ozone Season source is also subject to the Acid Rain Program, TR NO X Annual Trading Program, TR SO 2 Group 1 Trading Program, or TR SO 2 Group 2 Trading Program, then this natural person shall be the same natural person as the designated representative, as defined in § 72.2 of this chapter, § 97.402, § 97.602, or § 97.702 respectively.

Emissions means air pollutants
exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart.

Excess emissions means any ton of

NO X emitted from the TR NO X Ozone

Season units at a TR NO X Ozone Season source during a control period that
exceeds the TR NO X Ozone Season
emissions limitation for the source. Fossil fuel means— (1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or

(2) For purposes of applying §§ 97.504(b)(2)(i)(B), 97.504(b)(2)(ii)(B), and 97.504(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating
useful heat.

Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 1990 or any calendar year
thereafter.

Fuel oil means any petroleum-based fuel (including diesel fuel or petroleum derivatives such as oil tar) and any recycled or blended petroleum products or petroleum by-products used as a fuel whether in a liquid, solid, or gaseous

state.

General account means an Allowance Management System account, established under this subpart, that is not a compliance account.

Generator means a device that produces electricity.

Gross electrical output means, with regard to a unit, electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Heat input means, with regard to a unit for a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the designated representative and as modified by the
Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.

Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the
fuel.

Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:

(1) For the life of the unit;


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(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination;

or (3) For a period no less than 25 years or 70 percent of the economic useful life
of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as of
the initial installation of the unit as specified by the manufacturer of the

unit.

Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.

Nameplate capacity means, starting
from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of such completion as specified by the person conducting the physical change.

Newly affected TR NO X Ozone Season

unit means a unit that was not a TR NO X Ozone Season unit when it began operating but that thereafter becomes a

TR NO X Ozone Season unit.

Operate or operation means, with regard to a unit, to combust fuel.

Operator means any person who operates, controls, or supervises a TR

NO X Ozone Season unit or a TR NO X Ozone Season source and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit or source.

Owner means, with regard to a TR

NO X Ozone Season source or a TR NO X Ozone Season unit at a source respectively, any of the following

persons:

(1) Any holder of any portion of the legal or equitable title in a TR NO X Ozone Season unit at the source or the

TR NO X Ozone Season unit;

(2) Any holder of a leasehold interest

in a TR NO X Ozone Season unit at the
source or the TR NO X Ozone Season unit, provided that, unless expressly provided for in a leasehold agreement,

‘‘ owner ’’ shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or
income from such TR NO X Ozone Season unit;

(3) Any purchaser of power from a TR

NO X Ozone Season unit at the source or
the TR NO X Ozone Season unit under a life-of-the-unit, firm power contractual arrangement;

(4) Provided that, for purposes of applying the TR NO X Ozone Season assurance provisions in §§ 97.506(c)(2) and 97.525, if one or more owners (as defined in paragraphs (1) through (3) of this definition) of one or more TR NO X Ozone Season units in a State are wholly owned by another, common owner, all such owners shall be treated collectively as a single owner in the

State.

Owner’s assurance level means: (1) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.506(c)(2)(iii)(A) and not as described in § 97.506(c)(2)(iii)(B), the
owner’s share of the State NO X Ozone Season trading budget with the one-year variability limit for the State for such control period; or

(2) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.506(c)(2)(iii)(B), the owner’s share
of the State NO X Ozone Season trading budget with the three-year variability
limit for the State for such control period.

Owner’s share means: (1) With regard to a total amount of

NO X emissions from all TR NO X Ozone Season units in a State during a control period, the total tonnage of NO X emissions during such control period
from all of the owner’s TR NO X Ozone Season units in the State;

(2) With regard to a State NO X Ozone Season trading budget with a one-year variability limit for a control period, the amount (rounded to the nearest allowance) equal to the total amount of

TR NO X Ozone Season allowances allocated for such control period to all
of the owner’s TR NO X Ozone Season units in the State, multiplied by the sum
of the State NO X Ozone Season trading budget under § 97.510(a) and the State’s one-year variability limit under § 97.510(b) and divided by such State

NO X Ozone Season trading budget;

(3) With regard to a State NO X Ozone Season trading budget with a three-year variability limit for a control period, the amount (rounded to the nearest allowance) equal to the total amount of

TR NO X Ozone Season allowances allocated for such control period to all
of the owner’s TR NO X Ozone Season units in the State, multiplied by the sum
of the State NO X Ozone Season trading budget under § 97.510(a) and the State’s three-year variability limit under § 97.510(b) and divided by such State

NO X Ozone Season trading budget;

(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of NO X emissions and of TR

NO X Ozone Season allowances allocated for a control period, with regard to such unit, used in determining each owner’s share shall be the amount (rounded to
the nearest ton and the nearest allowance) equal to the unit’s NO X emissions and allocation of such allowances, respectively, for such control period multiplied by the percentage of ownership in the unit that the owner’s legal, equitable, leasehold,
or contractual reservation or entitlement in the unit comprises as of September 30 of such control period;

(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which

NO X mass emissions are reported for a control period for a year, the amount of tonnage of each unit’s NO X emissions used in determining each owner’s share for such control period shall be:

(i) The amount (rounded to the nearest ton) of NO X emissions reported at the common stack multiplied by the quotient of such unit’s heat input for such control period divided by the total heat input reported from the common stack for such control period;

(ii) An amount determined in accordance with a methodology that the
Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the
Administrator determines will be de minimis; or

(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.535; and

(6) Provided that, in the case of a unit that operates during, but is allocated no

TR NO X Ozone Season allowances for, a control period, the unit shall be treated, solely for purposes of this definition, as being allocated an amount (rounded to the nearest allowance) of

TR NO X Ozone Season allowances for such control period equal to the lesser
of—


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(i) The unit’s allowable NO X emission rate (in lb per MWe) applicable to such control period, multiplied by a capacity factor of 0.89 (if the unit is a coal-fired boiler), 0.22 (if the unit is a simple combustion turbine), or 0.72 (if the unit is a combined cycle turbine), multiplied by the unit’s maximum hourly load as reported in accordance with this subpart and by 3,672 hours/control period, and divided by 2,000 lb/ton; or

(ii) For a unit listed in appendix A to this subpart, the sum of the unit’s NO X emissions in the control period in the last three years during which the unit operated during the control period, divided by three.

Permanently retired means, with regard to a unit, a unit that is
unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.

Permitting authority means

‘‘ permitting authority ’’ as defined in §§ 70.2 and 71.2 of this chapter.

Potential electrical output capacity means 33 percent of a unit’s maximum design heat input, divided by 3,413 Btu/ kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.

Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of
business.

Recordation, record, or recorded means, with regard to TR NO X Ozone Season allowances, the moving of TR

NO X Ozone Season allowances by the Administrator into, out of, or between Allowance Management System accounts, for purposes of allocation, transfer, or deduction.

Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.

Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used
instead of the demolished or retired unit (the replaced unit).

Sequential use of energy means: (1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application

or process; or

(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.

Serial number means, for a TR NO X Ozone Season allowance, the unique identification number assigned to each

TR NO X Ozone Season allowance by the
Administrator.

Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion
turbine that is a ‘‘ solid waste

incineration unit ’’ as defined in section 129(g)(1) of the Clean Air Act.

Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the
definition of ‘‘ major source ’’

, ‘‘ stationary

source ’’ , or ‘‘ source ’’ as set forth and implemented in a title V operating permit program or any other program
under the Clean Air Act.

State means one of the States or the District of Columbia that is subject to
the TR NO X Ozone Season Trading Program pursuant to § 52.37(b) of this chapter.

Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(1) In person; (2) By United States Postal Service; or (3) By other means of dispatch or transmission and delivery;

(4) Provided that compliance with any

‘‘ submission ’’ or ‘‘ service ’’ deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.

Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.

Total energy input means total energy of all forms supplied to a unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as
follows:

LHV = HHV ¥ 10.55 (W + 9H)

Where: LHV = lower heating value of the form of energy in Btu/lb, HHV = higher heating value of the form of energy in Btu/lb, W = weight % of moisture in the form of energy, and H = weight % of hydrogen in the form of

energy. Total energy output means the sum of useful power and useful thermal energy produced by the unit.

TR NO X Annual Trading Program
means a multi-state NO X air pollution control and emission reduction program established by the Administrator in accordance with subpart AAAAA of this part and 52.37(a) of this chapter, as a means of mitigating interstate transport of fine particulates and NO X.

TR NO X Ozone Season allowance
means a limited authorization issued and allocated by the Administrator under this subpart to emit one ton of

NO X during a control period of the specified calendar year for which the authorization is allocated or of any calendar year thereafter under the TR

NO X Ozone Season Program.

TR NO X Ozone Season allowance
deduction or deduct TR NO X Ozone
Season allowances means the permanent withdrawal of TR NO X Ozone Season allowances by the Administrator from a compliance account, e.g., in order to account for compliance with the TR NO X Ozone
Season emissions limitation or assurance provisions.

TR NO X Ozone Season allowances
held or hold TR NO X Ozone Season
allowances means the TR NO X Ozone
Season allowances treated as included in an Allowance Management System account as of a specified point in time because at that time they:

(1) Have been recorded by the
Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR NO X Ozone Season
allowance transfer in accordance with this subpart; and

(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR NO X Ozone
Season allowance transfer in accordance with this subpart.

TR NO X Ozone Season emissions
limitation means, for a TR NO X Ozone Season source, the tonnage of NO X emissions authorized in a control period by the TR NO X Ozone Season
allowances available for deduction for the source under § 97.524(a) for such control period.

TR NO X Ozone Season Trading Program means a multi-state NO X air pollution control and emission reduction program established by the
Administrator in accordance with this subpart and 52.37(b) of this chapter, as a means of mitigating interstate transport of ozone and NO X.

TR NO X Ozone Season source means a source that includes one or more TR

NO X Ozone Season units.


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TR NO X Ozone Season unit means a unit that is subject to the TR NO X Ozone Season Trading Program under § 97.504.

TR SO 2 Group 1 Trading Program
means a multi-state SO 2 air pollution control and emission reduction program established by the Administrator in accordance with subpart CCCCC of this part and 52.38(b) of this chapter, as a means of mitigating interstate transport of fine particulates and SO 2.

TR SO 2 Group 2 Trading Program
means a multi-state SO 2 air pollution control and emission reduction program established by the Administrator in accordance with subpart DDDDD of this part and 52.38(c) of this chapter, as a means of mitigating interstate transport of fine particulates and SO 2.

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary,
fossil-fuel-fired combustion device.

Unit operating day means a calendar day in which a unit combusts any fuel.

Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.

Useful power means electricity or mechanical energy that a unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means thermal energy that is:

(1) Made available to an industrial or commercial process (not a power production process), excluding any heat
contained in condensate return or makeup water;

(2) Used in a heating application (e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application (i.e., in an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to

customers.

**§ 97.503 Measurements, abbreviations, and acronyms.** 

Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:

Btu—British thermal unit

CO 2 —carbon dioxide

H 2 O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour lb—pound
mmBtu—million Btu MWe—megawatt electrical MWh—megawatt hour

NO X —nitrogen oxides

O 2 —oxygen ppm—parts per million scfh—standard cubic feet per hour

SO 2 —sulfur dioxide

yr—year

**§ 97.504 Applicability.**

(a) Except as provided in paragraph (b) of this section:

(1) The following units in a State shall
be TR NO X Ozone Season units, and any
source that includes one or more such
units shall be a TR NO X Ozone Season source, subject to the requirements ofthis subpart: Any stationary, fossil-fuelfired boiler or stationary, fossil-fuelfired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a

TR NO X Ozone Season unit begins to
combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit shall become a TR NO X Ozone Season unit as provided in paragraph (a)(1) of this section on the
first date on which it both combusts fossil fuel and serves such generator.

(b) Any unit in a State that otherwise

is a TR NO X Ozone Season unit under paragraph (a) of this section and that meets the requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR NO X Ozone Season unit:

(1)(i) Any unit: (A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and

(B) Not serving at any time, since thelater of November 15, 1990 or the startup of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system
for sale.

(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12- month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the
unit shall become a TR NO X Ozone Season unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of paragraph (b)(1)(i)(B) of this section.

(2)(i) Any unit commencing operation before January 1, 1985:

(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average Ozone Season fuel consumption of fossil fuel for 1985– 1987 less than 20 percent (on a Btu basis) and an average Ozone Season fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(ii) Any unit commencing operation on or after January 1, 1985:

(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average Ozone Season fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average Ozone Season fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a

TR NO X Ozone Season unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a solid waste incineration unit or January 1 after the first 3 consecutive calendar years after 1990 for which the unit has an average Ozone Season fuel consumption of fossil fuel of 20 percent or more.

(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR NO X Ozone Season Trading Program to the unit or other equipment.

(1) Petition content. The petition shall be in writing and include the
identification of the unit or other


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equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying
official: ‘‘ I am authorized to make this
submission on behalf of the owners and operators of the unit or other equipment
for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR NO X Ozone Season Trading Program to the unit or other equipment shall be binding on any permitting authority unless the
Administrator determines that the petition or other documents or information provided in connection with the petition contained significant,
relevant errors or omissions.

**§ 97.505 Retired unit exemption.**

(a)(1) Any TR NO X Ozone Season unit that is permanently retired and is not a

TR NO X Ozone Season opt-in unit shall be exempt from § 97.506(b) and (c)(1), § 97.524, and §§ 97.530 through 97.535.

(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR NO X Ozone Season unit is permanently retired. Within 30 days of the unit’s permanent retirement, the designated representative shall submit a statement
to the Administrator. The statement shall state, in a format prescribed by the Administrator, that the unit was permanently retired on a specified date and will comply with the requirements of paragraph (b) of this section.

(b) Special provisions. (1) A unit exempt under paragraph (a) of this section shall not emit any NO X , starting on the date that the exemption takes
effect. (2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR

NO X Ozone Season Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect.

(4) A unit exempt under paragraph (a) of this section shall lose its exemption
on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.

**§ 97.506 Standard requirements.**

(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.513 through 97.518.

(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each TR

NO X Ozone Season source and each TR

NO X Ozone Season unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of §§ 97.530 through

97.535.

(2) The emissions data determined in accordance with §§ 97.530 through
97.535 shall be used to calculate
allocations of TR NO X Ozone Season allowances under §§ 97.511(a)(2) and (b)
and 97.512 and to determine compliance with the TR NO X Ozone
Season emissions limitation and assurance provisions under paragraph (c) of this section, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location
determined in accordance with §§ 97.530 through 97.535 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be

zero.

(c) NO X emissions requirements —(1)

TR NO X Ozone Season emissions
limitation. (i) As of the allowance transfer deadline for a control period, the owners and operators of each TR

NO X Ozone Season source and each TR

NO X Ozone Season unit at the source shall hold, in the source’s compliance account, TR NO X Ozone Season
allowances available for deduction for such control period under § 97.524(a) in
an amount not less than the tons of total

NO X emissions for such control period
from all TR NO X Ozone Season units at
the source.

(ii) If a TR NO X Ozone Season source

emits NO X during any control period in
excess of the TR NO X Ozone Season
emissions limitation set forth in paragraph (c)(1)(i) of this section, then:

(A) The owners and operators of the
source and each TR NO X Ozone Season
unit at the source shall hold the TR NO X Ozone Season allowances required for deduction under § 97.524(d) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act; and

(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.

(2) TR NO X Ozone Season assurance provisions. (i) If the total amount of

NO X emissions from all TR NO X Ozone Season units in a State during a control period in 2014 or any year thereafter
exceeds the State assurance level as described in paragraph (c)(2)(iii) of this section, then each owner whose share of
such NO X emissions during such control period exceeds the owner’s
assurance level for the State and such control period shall hold, in a compliance account designated by the
owner in accordance with § 97.525(b)(4)(ii), TR NO X Ozone Season
allowances available for deduction for such control period under § 97.525(a) in an amount equal to the product, as determined by the Administrator in accordance with § 97.525(b), of multiplying—

(A) The quotient (rounded to the nearest whole number) of the amount by
which the owner’s share of such NO X emissions exceeds the owner’s assurance level divided by the sum of the amounts, determined for all such owners, by which each owner’s share of
such NO X emissions exceeds that owner’s assurance level; and

(B) The amount by which total NO X emissions for all TR NO X Ozone Season


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units in the State for such control period
exceed the State assurance level as
determined in accordance with paragraph (c)(2)(iii) of this section.

(ii) The owner shall hold the TR NO X Ozone Season allowances required under paragraph (c)(2)(i) of this section, as of midnight of August 1 (if it is a business day), or midnight of the first business day thereafter (if August 1 is not a business day), immediately after such control period.

(iii) The total amount of NO X emissions from all TR NO X Ozone Season units in a State during a control period in 2014 or any year thereafter
exceeds the State assurance level:

(A) If such total amount of NO X emissions exceeds the sum, for such control period, of the State NO X Ozone Season trading budget and the State’s one-year variability limit under § 97.510(b); or

(B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount
of NO X emissions and the total amounts
of NO X emissions from all TR NO X Ozone Season units in the State during the control periods in the immediately preceding two years exceeds the sum, for such control period, of the State NO X Ozone Season trading budget and the State’s three-year variability limit under § 97.510(b);

(C) Provided that the amount by
which such total amount of NO X emissions exceeds the State assurance level shall be the greater of the amounts
of the exceedance calculated under paragraph (c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of this

section.

(iv) It shall not be a violation of this subpart or of the Clean Air Act if the
total amount of NO X emissions from all

TR NO X Ozone Season units in a State during a control period exceeds the
State assurance level or if an owner’s
share of total NO X emissions from the

TR NO X Ozone Season units in a State during a control period exceeds the
owner’s assurance level.

(v) To the extent an owner fails to
hold TR NO X Ozone Season allowances for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section,

(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and

(B) Each TR NO X Ozone Season
allowance that the owner fails to hold for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section and each day of such control period shall constitute a separate violation of this subpart and the Clean

Air Act.

(3) Compliance periods. A TR NO X Ozone Season unit shall be subject to the requirements:

(i) Under paragraph (c)(1) of this section for the control period starting on the later of September 1, 2012 or the deadline for meeting the unit’s monitor certification requirements under § 97.530(b) and for each control period thereafter; and

(ii) Under paragraph (c)(2) of this section for the control period starting on the later of September 1, 2014 or the deadline for meeting the unit’s monitor certification requirements under § 97.530(b) and for each control period
thereafter.

(4) Vintage of deducted allowances. A

TR NO X Ozone Season allowance shall not be deducted, for compliance with the requirements under paragraphs (c)(1) and (2) of this section, for a control period in a calendar year before the year for which the TR NO X Ozone
Season allowance was allocated.

(5) Allowance Management System requirements. Each TR NO X Ozone Season allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with this subpart.

(6) Limited authorization. (i) A TR

NO X Ozone Season allowance is a
limited authorization to emit one ton of

NO X in accordance with the TR NO X Ozone Season Trading Program.

(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to
terminate or limit such authorization to
the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean

Air Act.

(7) Property right. A TR NO X Ozone
Season allowance does not constitute a property right.

(d) Title V Permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction,
or transfer of TR NO X Ozone Season
allowances in accordance with this subpart.

(2) A description of whether a unit is required to monitor and report NO X emissions using a continuous emission monitoring system (under subpart H of part 75 of this chapter), an excepted monitoring system (under appendices D and E to part 75 of this chapter), a low mass emissions excepted monitoring methodology (under § 75.19 of this chapter), or an alternative monitoring system (under subpart E of part 75 of this chapter) in accordance with §§ 97.530 through 97.535 may be added to, or changed in, a title V permit using minor permit modification procedures in accordance with §§ 70.7(e)(2) and 71.7(e)(1) of this chapter, provided that the requirements applicable to the described monitoring and reporting (as added or changed, respectively) are already incorporated in such permit. This paragraph explicitly provides that the addition of, or change to, a unit’s description as described in the prior sentence is eligible for minor permit modification procedures in accordance with §§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.

(e) Additional recordkeeping and reporting requirements.

(1) Unless otherwise provided, the owners and operators of each TR NO X Ozone Season source and each TR NO X Ozone Season unit at the source shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a period of 5 years
from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by the Administrator.

(i) The certificate of representation under § 97.516 for the designated representative for the source and each

TR NO X Ozone Season unit at the
source and all documents that
demonstrate the truth of the statements in the certificate of representation; provided that the certificate and
documents shall be retained on site at the source beyond such 5-year period until such documents are superseded
because of the submission of a new certificate of representation under § 97.516 changing the designated representative.

(ii) All emissions monitoring information, in accordance with this subpart.

(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR NO X Ozone Season Trading Program, including any monitoring plans and monitoring system certification and recertification applications.

(2) The designated representative of a

TR NO X Ozone Season source and each

TR NO X Ozone Season unit at the
source shall make all submissions required under the TR NO X Ozone Season Trading Program, including any submissions required for compliance
with the TR NO X Ozone Season assurance provisions. This requirement does not change, create an exemption from, or or otherwise affect the responsible official submission requirements under a title V operating


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permit program in parts 70 and 71 of this chapter.

(f) Liability. (1) Any provision of the

TR NO X Ozone Season Trading Program that applies to a TR NO X Ozone Season source or the designated representative
of a TR NO X Ozone Season source shall also apply to the owners and operators
of such source and of the TR NO X Ozone Season units at the source.

(2) Any provision of the TR NO X Ozone Season Trading Program that applies to a TR NO X Ozone Season unit or the designated representative of a TR

NO X Ozone Season unit shall also apply to the owners and operators of such

unit.

(g) Effect on other authorities. No provision of the TR NO X Ozone Season Trading Program or exemption under § 97.505 shall be construed as exempting or excluding the owners and operators, and the designated representative, of a TR NO X Ozone

Season source or TR NO X Ozone Season unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

**§ 97.507 Computation of time.**

(a) Unless otherwise stated, any time period scheduled, under the TR NO X Ozone Season Trading Program, to begin
on the occurrence of an act or event shall begin on the day the act or event

occurs.

(b) Unless otherwise stated, any time period scheduled, under the TR NO X Ozone Season Trading Program, to begin
before the occurrence of an act or event shall be computed so that the period ends the day before the act or event

occurs.

(c) Unless otherwise stated, if the final day of any time period, under the TR NO X Ozone Season Trading Program,
falls on a weekend or a State or Federal holiday, the time period shall be extended to the next business day.

**§ 97.508 Administrative appeal procedures.** 

The administrative appeal procedures
for decisions of the Administrator under
the TR NO X Ozone Season Trading Program are set forth in part 78 of this chapter.

**§ 97.509 [Reserved]**

**§ 97.510 State NO** X **Ozone Season trading budgets, new-unit set-asides, and variability** 
**limits.**

(a) The State NO X Ozone Season trading budgets and new-unit set-asides
for allocations of TR NO X Ozone Season allowances for the control periods in
2012 and thereafter are as follows:

State NO X ozone season trading budget (tons)* New-unit set-aside (tons)

For 2012 and

thereafter For 2012 and thereafter

Alabama ........................................................................................................................ ............................... 29,738 892
Arkansas ....................................................................................................................... ............................... 16,660 500
Connecticut .................................................................................................................... .............................. 1,315 39
Delaware ....................................................................................................................... ............................... 2,450 74
District of Columbia ........................................................................................................... .......................... 105 3
Florida ........................................................................................................................ .................................. 56,939 1,708 Georgia ........................................................................................................................ ................................ 32,144 964
Illinois ....................................................................................................................... .................................... 23,570 707
Indiana ........................................................................................................................ ................................. 49,987 1,500
Kansas ......................................................................................................................... ................................ 21,433 643 Kentucky ....................................................................................................................... ............................... 30,908 927
Louisiana ...................................................................................................................... ................................ 21,220 637 Maryland ....................................................................................................................... ............................... 7,232 217 Michigan ....................................................................................................................... ................................ 28,253 848 Mississippi .................................................................................................................... ................................ 16,530 496 New Jersey ..................................................................................................................... ............................. 5,269 158
New York ....................................................................................................................... .............................. 11,090 333
North Carolina ................................................................................................................. ............................. 23,539 706
Ohio ........................................................................................................................... .................................. 40,661 1,220
Oklahoma ....................................................................................................................... .............................. 37,087 1,113 Pennsylvania ................................................................................................................... ............................. 48,271 1,448
South Carolina ................................................................................................................. ............................ 15,222 457
Tennessee ...................................................................................................................... ............................. 11,575 347
Texas .......................................................................................................................... ................................. 75,574 2,267 Virginia ....................................................................................................................... .................................. 12,608 378 West Virginia .................................................................................................................. .............................. 22,234 667

Total .......................................................................................................................... ............................ 641,614 19,249

* Without variability limits.

(b) The States’ one-year and three-year variability limits for the State NO X Ozone Season trading budgets for the control periods in 2014 and thereafter

are as follows:


### 45401 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

State One-year variability limits Three-year variability limits

2014 and thereafter (tons) 2016 and thereafter (tons)

Alabama ........................................................................................................................ ............................... 2,974 1,717
Arkansas ....................................................................................................................... ............................... 2,100 1,212
Connecticut .................................................................................................................... .............................. 2,100 1,212
Delaware ....................................................................................................................... ............................... 2,100 1,212
District of Columbia ........................................................................................................... .......................... 2,100 1,212
Florida ........................................................................................................................ .................................. 5,694 3,287 Georgia ........................................................................................................................ ................................ 3,214 1,856
Illinois ....................................................................................................................... .................................... 2,357 1,361
Indiana ........................................................................................................................ ................................. 4,999 2,886
Kansas ......................................................................................................................... ................................ 2,143 1,237 Kentucky ....................................................................................................................... ............................... 3,091 1,784
Louisiana ...................................................................................................................... ................................ 2,122 1,225 Maryland ....................................................................................................................... ............................... 2,100 1,212 Michigan ....................................................................................................................... ................................ 2,825 1,631 Mississippi .................................................................................................................... ................................ 2,100 1,212 New Jersey ..................................................................................................................... ............................. 2,100 1,212
New York ....................................................................................................................... .............................. 2,100 1,212
North Carolina ................................................................................................................. ............................. 2,354 1,359
Ohio ........................................................................................................................... .................................. 4,066 2,348
Oklahoma ....................................................................................................................... .............................. 3,709 2,141 Pennsylvania ................................................................................................................... ............................. 4,827 2,787
South Carolina ................................................................................................................. ............................ 2,100 1,212
Tennessee ...................................................................................................................... ............................. 2,100 1,212
Texas .......................................................................................................................... ................................. 7,557 4,363 Virginia ....................................................................................................................... .................................. 2,100 1,212 West Virginia .................................................................................................................. .............................. 2,223 1,284

**§ 97.511 Timing requirements for TR NO** X **Ozone Season allowance allocations.**

(a) Existing units. (1) TR NO X Ozone Season allowances are allocated, for the control periods in 2012 and each year thereafter, as set forth in appendix A to this subpart. Listing a unit in such appendix does not constitute a
determination that the unit is a TR NO X Ozone Season unit, and not listing a unit in such appendix does not
constitute a determination that the unit

is not a TR NO X Ozone Season unit.

(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being
allocated TR NO X Ozone Season allowances does not operate, starting after 2011, during the control period in three consecutive years, such unit will
not be allocated the TR NO X Ozone Season allowances set forth in appendix A to this subpart for the unit for the control periods in the seventh year after the first such year and in each year after that seventh year. All TR NO X Ozone
Season allowances that would otherwise
have been allocated to such unit will be
allocated to the new unit set-aside for the respective years involved. If such unit resumes operation, the
Administrator will allocate TR NO X Ozone Season allowances to the unit in accordance with paragraph (b) of this

section.

(b) New units. (1) By April 1, 2012 and April 1 of each year thereafter, the Administrator will calculate the TR

NO X Ozone Season allowance allocation
for each TR NO X Ozone Season unit, in accordance with § 97.512, for the control period in the year of the applicable calculation deadline under this paragraph and will promulgate a notice of availability of the results of the
calculations.

(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced
in such notice.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations are in accordance with § 97.512 and §§ 97.506(b)(2) and 97.530 through

97.535.

(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By June 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(c) Units that are not TR NO X Ozone

Season units. For each control period in 2012 and thereafter, if the Administrator
determines that TR NO X Ozone Season
allowances were allocated under paragraph (a) of this section for the control period to a recipient that is not actually a TR NO X Ozone Season unit under § 97.504 as of May 1, 2012 or whose deadline for meeting monitor certification requirements under § 97.530(b)(1) and (2) is after May 1,
2012 or if the Administrator determines
that TR NO X Ozone Season allowances were allocated under paragraph (b) of this section and § 97.512 for the control period to a recipient that is not actually

a TR NO X Ozone Season unit under § 97.504 as of May 1 of the control period, then the Administrator will notify the designated representative and
will act in accordance with the following procedures:

(1) Except as provided in paragraph (c)(2) or (3) of this section, the
Administrator will not record such TR

NO X Ozone Season allowances under § 97.521.

(2) If the Administrator already
recorded such TR NO X Ozone Season allowances under § 97.521 and if the
Administrator makes such determination before making deductions
for the source that includes such recipient under § 97.524(b) for such control period, then the Administrator
will deduct from the account in which
such TR NO X Ozone Season allowances


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were recorded an amount of TR NO X Ozone Season allowances allocated for the same or a prior control period equal to the amount of such already recorded

TR NO X Ozone Season allowances. The authorized account representative shall
ensure that there are sufficient TR NO X Ozone Season allowances in such account for completion of the
deduction.

(3) If the Administrator already
recorded such TR NO X Ozone Season allowances under § 97.521 and if the
Administrator makes such determination after making deductions
for the source that includes such recipient under § 97.524(b) for such control period, then the Administrator will not make any deduction to take account of such already recorded TR

NO X Ozone Season allowances.

(4) The Administrator will transfer the

TR NO X Ozone Season allowances that are not recorded, or that are deducted, in accordance with paragraphs (c)(1) and (2) of this section to the new unit set-aside, for the State in which such recipient is located, for the control period in the year of such transfer if the notice required in paragraph (b)(1) of this section for the control period in that year has not been promulgated or, if such notice has been promulgated, in the next year.

**§ 97.512 TR NO** X **Ozone Season allowance**

**allocations for new units.**

(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR NO X Ozone
Season allowances to TR NO X Ozone
Season units in a State that are not listed in appendix A to this subpart, to

TR NO X Ozone Season units that are so
listed and whose allocation of NO X Ozone Season allowances for such control period is covered by § 97.511(c)(1) or (2), and to TR NO X Ozone Season units that are so listed and, pursuant to § 97.511(a)(2), are not
allocated TR NO X Ozone Season allowances for such control period but that operate during the immediately preceding control period:

(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be
allocated TR NO X Ozone Season allowances in an amount equal to the applicable amount of tons of NO X emissions as set forth in § 97.510(a).
Each new unit set-aside will be
allocated additional TR NO X Ozone
Season allowances in accordance with § 97.511(a)(2) and (c)(4).

(2) The designated representative of
such TR NO X Ozone Season unit may submit to the Administrator a request, in a format prescribed by the Administrator, to be allocated TR NO X Ozone Season allowances for a control period, starting with the later of the control period in 2012, the first control period after the control period in which
the TR NO X Ozone Season unit commences commercial operation (for a unit not listed in appendix A to this subpart), or the first control period after the control period in which the unit resumes operation (for a unit listed in appendix A of this subpart) and for each subsequent control period.

(i) The request must be submitted on or before February 1 immediately preceding the first control period for
which TR NO X Ozone Season allowances are sought and after the date
on which the TR NO X Ozone Season unit commences commercial operation (for a unit not listed in appendix A of this subpart) or on which the unit resumes operation (for a unit listed in appendix A of this subpart).

(ii) For each control period for which an allocation is sought, the request must
be for TR NO X Ozone Season allowances in an amount equal to the
unit’s total tons of NO X emissions during the immediately preceding control period.

(3) The Administrator will review
each TR NO X Ozone Season allowance allocation request under paragraph (a)(2) of this section and will accept the request only if it meets the requirements of paragraph (a)(2) of this section. The
Administrator will allocate TR NO X Ozone Season allowances for each control period pursuant to an accepted request as follows:

(i) After February 1 immediately preceding such control period, the
Administrator will determine the sum of
the TR NO X Ozone Season allowances requested in all accepted allowance allocation requests for such control period.

(ii) If the amount of TR NO X Ozone
Season allowances in the new unit setaside for such control period is greater than or equal to the sum under paragraph (a)(3)(i) of this section, then
the Administrator will allocate the
amount of TR NO X Ozone Season allowances requested to each TR NO X Ozone Season unit covered by an accepted allowance allocation request.

(iii) If the amount of TR NO X Ozone
Season allowances in the new unit setaside for such control period is less than the sum under paragraph (a)(3)(i) of this section, then the Administrator will
allocate to each TR NO X Ozone Season unit covered by an accepted allowance allocation request the amount of the TR

NO X Ozone Season allowances requested, multiplied by the amount of

TR NO X Ozone Season allowances in
the new unit set-aside for such control period, divided by the sum determined under paragraph (a)(3)(i) of this section,
and rounded to the nearest allowance.

(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.511(b), each designated representative that submitted an allowance allocation request of the
amount of TR NO X Ozone Season allowances (if any) allocated for such control period to the TR NO X Ozone Season unit covered by the request.

(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any
unallocated TR NO X Ozone Season
allowances remain in the new unit setaside under paragraph (a) of this section for a State for such control period, the
Administrator will allocate to each TR

NO X Ozone Season unit that is in the State, is listed in appendix A to this subpart, and continues to be allocated

TR NO X Ozone Season allowances for such control period in accordance with § 97.511(a)(2), an amount of TR NO X Ozone Season allowances equal to the following: The total amount of such remaining unallocated TR NO X Ozone
Season allowances in such new unit setaside, multiplied by the unit’s allocation under § 97.511(a) for such control period, divided by the remainder of the amount of tons in the applicable State

NO X Ozone Season trading budget
minus the amount of tons in such new unit set-aside, and rounded to the
nearest allowance.

**§ 97.513 Authorization of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.515,
each TR NO X Ozone Season source, including all TR NO X Ozone Season units at the source, shall have one and only one designated representative, with regard to all matters under the TR NO X Ozone Season Trading Program.

(1) The designated representative shall be selected by an agreement binding on the owners and operators of
the source and all TR NO X Ozone
Season units at the source and shall act
in accordance with the certification statement in § 97.516(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.516:

(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source
and each TR NO X Ozone Season unit at


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the source in all matters pertaining to
the TR NO X Ozone Season Trading Program, notwithstanding any agreement between the designated representative and such owners and operators; and

(ii) The owners and operators of the
source and each TR NO X Ozone Season unit at the source shall be bound by any
decision or order issued to the designated representative by the Administrator regarding the source or any such unit.

(b) Except as provided under § 97.515,
each TR NO X Ozone Season source may have one and only one alternate designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.

(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR NO X Ozone Season units at the source and
shall act in accordance with the
certification statement in § 97.516(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.516,

(i) The alternate designated representative shall be authorized;

(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and

(iii) The owners and operators of the
source and each TR NO X Ozone Season unit at the source shall be bound by any
decision or order issued to the alternate designated representative by the Administrator regarding the source or any such unit.

(c) Except in this section, § 97.502, and §§ 97.514 through 97.518, whenever
the term ‘‘ designated representative ’’ is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.

**§ 97.514 Responsibilities of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.518 concerning delegation of authority to make submissions, each submission
under the TR NO X Ozone Season Trading Program shall be made, signed, and certified by the designated representative or alternate designated representative for each TR NO X Ozone Season source and TR NO X Ozone
Season unit for which the submission is
made. Each such submission shall include the following certification statement by the designated representative or alternate designated representative: ‘‘ I am authorized to make
this submission on behalf of the owners and operators of the source or units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(b) The Administrator will accept or
act on a submission made for a TR NO X Ozone Season source or a TR NO X Ozone Season unit only if the submission has been made, signed, and certified in accordance with paragraph (a) of this section and § 97.518.

**§ 97.515 Changing designated representative and alternate designated**  **representative; changes in owners and operators.** 

(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.516. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date
when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the TR NO X Ozone Season
source and the TR NO X Ozone Season
units at the source.

(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.516. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the
time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the TR NO X Ozone Season source and the TR NO X Ozone Season units at the source.

(c) Changes in owners and operators. (1) In the event an owner or operator of

a TR NO X Ozone Season source or a TR

NO X Ozone Season unit is not included in the list of owners and operators in the certificate of representation under § 97.516, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the source or unit, and the decisions and orders of the Administrator, as if the owner or operator were included in such list.

(2) Within 30 days after any change in the owners and operators of a TR NO X Ozone Season source or a TR NO X Ozone Season unit, including the addition of a new owner or operator, the designated representative or any alternate designated representative shall
submit a revision to the certificate of representation under § 97.516 amending the list of owners and operators to include the change.

**§ 97.516 Certificate of representation.**

(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:

(1) Identification of the TR NO X Ozone Season source, and each TR NO X Ozone Season unit at the source, for which the certificate of representation is submitted, including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type, identification number and nameplate capacity (in MWe rounded to the nearest tenth) of each generator served by each such unit, and actual or projected date of commencement of commercial operation.

(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

(3) A list of the owners and operators
of the TR NO X Ozone Season source and
of each TR NO X Ozone Season unit at
the source.

(4) The following certification statements by the designated representative and any alternate designated representative—


### 45404 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

(i) ‘‘ I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR

NO X Ozone Season unit at the source. ’’

(ii) ‘‘ I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR

NO X Ozone Season Trading Program on behalf of the owners and operators of
the source and of each TR NO X Ozone
Season unit at the source and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions and by any order issued to me by the Administrator regarding the source or unit. ’’

(iii) ‘‘ Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR NO X Ozone Season unit, or where a utility or industrial customer purchases power
from a TR NO X Ozone Season unit under a life-of-the-unit, firm power contractual arrangement, I certify that: I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the source
and of each TR NO X Ozone Season unit at the source; and TR NO X Ozone Season allowances and proceeds of transactions involving TR NO X Ozone
Season allowances will be deemed to be held or distributed in proportion to each holder’s legal, equitable, leasehold, or contractual reservation or entitlement, except that, if such multiple holders have expressly provided for a different
distribution of TR NO X Ozone Season allowances by contract, TR NO X Ozone Season allowances and proceeds of transactions involving TR NO X Ozone
Season allowances will be deemed to be
held or distributed in accordance with
the contract. ’’

(5) The signature of the designated representative and any alternate designated representative and the dates signed.

(b) Unless otherwise required by the Administrator, documents of agreement
referred to in the certificate of representation shall not be submitted to
the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

**§ 97.517 Objections concerning designated representative and alternate**  **designated representative.**

(a) Once a complete certificate of representation under § 97.516 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.516 is received by the Administrator.

(b) Except as provided in § 97.515(a) or (b), no objection or other
communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator
under the TR NO X Ozone Season Trading Program.

(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR

NO X Ozone Season allowance transfers.

**§ 97.518 Delegation by designated representative and alternate designated**  **representative.**

(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(c) In order to delegate authority to
make an electronic submission to the
Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;

(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an

‘‘ agent ’’ );

(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and

(4) The following certification statements by such designated representative or alternate designated representative:

(i) ‘‘ I agree that any electronic
submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.518(d) shall be deemed to be an electronic submission by me. ’’

(ii) ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.518(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me
under 40 CFR 97.518 is terminated. ’’

.

(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(e) Any electronic submission covered by the certification in paragraph (c)(4)(i)
of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall
be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.

**§ 97.519 [Reserved]**

**§ 97.520 Establishment of Allowance Management System accounts.** 

(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.516, the
Administrator will establish a compliance account for the TR NO X Ozone Season source for which the certificate of representation was submitted, unless the source already has a compliance account. The designated representative and any alternate designated representative of the source


### 45405 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

shall be the authorized account representative and the alternate authorized account representative respectively of the compliance account.

(b) General accounts— (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring TR

NO X Ozone Season allowances, by submitting to the Administrator a complete application for a general account. Such application shall designate one and only one authorized account representative and may designate one and only one alternate authorized account representative who may act on behalf of the authorized account representative.

(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR NO X Ozone Season allowances held in the general account.

(B) The agreement by which the
alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act
in lieu of the authorized account representative.

(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:

(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;

(B) An identifying name for the general account;

(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the TR NO X Ozone Season allowances held in the general account;

(D) The following certification statement by the authorized account representative and any alternate authorized account representative: ‘‘ I certify that I was selected as the authorized account representative or the
alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR NO X Ozone Season allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR NO X Ozone Season Trading Program on behalf of such persons and that each such person shall be fully bound by my representations, actions, inactions, or submissions and by any order or decision issued to me by the Administrator regarding the general

account. ’’

(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.

(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted
to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted and upon and after such receipt by the Administrator:

(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to TR

NO X Ozone Season allowances held in the general account in all matters pertaining to the TR NO X Ozone Season Trading Program, notwithstanding any agreement between the authorized account representative and such person.

(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.

(C) Each person who has an ownership interest with respect to TR

NO X Ozone Season allowances held in the general account shall be bound by any order or decision issued to the authorized account representative or
alternate authorized account representative by the Administrator regarding the general account.

(ii) Except as provided in paragraph (b)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to TR

NO X Ozone Season allowances held in the general account. Each such submission shall include the following certification statement by the authorized account representative or any alternate authorized account representative: ‘‘ I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the

TR NO X Ozone Season allowances held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the
statements and information submitted
in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(iii) Except in this section, whenever
the term ‘‘ authorized account representative ’’ is used in this subpart,
the term shall be construed to include the authorized account representative or any alternate authorized account representative.

(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the TR NO X Ozone Season allowances in the general

account.

(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new


### 45406 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the

TR NO X Ozone Season allowances in the general account.

(iii)(A) In the event a person having an ownership interest with respect to

TR NO X Ozone Season allowances in the general account is not included in the list of such persons in the application for a general account, such person shall be deemed to be subject to and bound by the application for a general account, the representation, actions, inactions, and submissions of the authorized account representative and any alternate authorized account representative of the account, and the
decisions and orders of the Administrator, as if the person were
included in such list.

(B) Within 30 days after any change in the persons having an ownership interest with respect to NO X Ozone Season allowances in the general account, including the addition of a new person, the authorized account representative or any alternate authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the TR NO X Ozone Season allowances in the general account to include the change.

(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (b)(1)
of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the
Administrator.

(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication
submitted to the Administrator concerning the authorization, or any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the
Administrator under the TR NO X Ozone Season Trading Program.

(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR

NO X Ozone Season allowance transfers.

(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(iii) In order to delegate authority to
make an electronic submission to the
Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or
alternate authorized account representative, as appropriate, must
submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any)
of such authorized account representative or alternate authorized account representative;

(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to

as an ‘‘ agent ’’ );

(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;

(D) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ I agree that any
electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is
made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.520(b)(5)(iv) shall be deemed to be an electronic submission by me. ’’ ; and

(E) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.520(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.520(b)(5) is terminated. ’’

.

(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or
alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or
alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of
this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.

(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR NO X Ozone
Season allowance transfer under § 97.522 for any TR NO X Ozone Season
allowances in the account to one or more other Allowance Management System accounts.

(ii) If a general account has no TR

NO X Ozone Season allowance transfers
to or from the account for a 12-month period or longer and does not contain any TR NO X Ozone Season allowances, the Administrator may notify the authorized account representative for
the account that the account will be closed after 20 business days after the
notice is sent. The account will be closed after the 20-day period unless, before the end of the 20-day period, the Administrator receives a correctly
submitted TR NO X Ozone Season allowance transfer under § 97.522 to the account or a statement submitted by the authorized account representative or
alternate authorized account representative demonstrating to the satisfaction of the Administrator good


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cause as to why the account should not
be closed.

(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of
this section.

(d) Responsibilities of authorized account representative and alternate authorized account representative. After
the establishment of an Allowance Management System account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction
or transfer of TR NO X Ozone Season allowances in the account, only if the submission has been made, signed, and certified in accordance with §§ 97.514(a) and 97.518 or paragraphs (b)(2)(ii) and (b)(5) of this section.

**§ 97.521 Recordation of TR NO** X **Ozone**
**Season allowance allocations.**

(a) By September 1, 2011, the
Administrator will record in each TR

NO X Ozone Season source’s compliance
account the TR NO X Ozone Season
allowances allocated for the TR NO X Ozone Season units at the source in accordance with §§ 97.511(a) for the control periods in 2012, 2013, and 2014.

(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will
record in each TR NO X Ozone Season source’s compliance account the TR

NO X Ozone Season allowances allocated
for the TR NO X Ozone Season units at
the source in accordance with § 97.511(a) for the control period in the third year after the year of the applicable recordation deadline under this paragraph.

(c) By June 1, 2012 and June 1 of each year thereafter, the Administrator will
record in each TR NO X Ozone Season source’s compliance account the TR

NO X Ozone Season allowances allocated
for the TR NO X Ozone Season units at the source in accordance with § 97.512 for the control period in the year of the applicable recordation deadline under this paragraph.

(d) When recording the allocation of

TR NO X Ozone Season allowances for a

TR NO X Ozone Season unit in a compliance account, the Administrator will assign each TR NO X Ozone Season allowance a unique identification number that will include digits identifying the year of the control period for which the TR NO X Ozone
Season allowance is allocated.

**§ 97.522 Submission of TR NO** X **Ozone**
**Season allowance transfers.**

(a) An authorized account representative seeking recordation of a TR NO X Ozone Season allowance
transfer shall submit the transfer to the
Administrator.

(b) A TR NO X Ozone Season allowance transfer shall be correctly
submitted if:

(1) The transfer includes the following elements, in a format prescribed by the
Administrator:

(i) The account numbers established by the Administrator for both the transferor and transferee accounts;

(ii) The serial number of each TR NO X Ozone Season allowance that is in the
transferor account and is to be transferred; and

(iii) The name and signature of the authorized account representative of the transferor account and the date signed;
and

(2) When the Administrator attempts to record the transfer, the transferor
account includes each TR NO X Ozone Season allowance identified by serial
number in the transfer.

**§ 97.523 Recordation of TR NO** X **Ozone**
**Season allowance transfers.**

(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR NO X Ozone Season allowance transfer, the
Administrator will record a TR NO X Ozone Season allowance transfer by moving each TR NO X Ozone Season
allowance from the transferor account to the transferee account as specified by the request, provided that the transfer is correctly submitted under § 97.522.

(b)(1) A TR NO X Ozone Season
allowance transfer that is submitted for
recordation after the allowance transfer deadline for a control period and that includes any TR NO X Ozone Season allowances allocated for any control period before such allowance transfer
deadline will not be recorded until after the Administrator completes the deductions under § 97.524 for the control period immediately before such
allowance transfer deadline.

(2) A TR NO X Ozone Season
allowance transfer that is submitted for
recordation after the deadline for holding TR NO X Ozone Season allowances described in § 97.525(b)(5) and that includes any TR NO X Ozone
Season allowances allocated for a control period before the year of such
deadline will not be recorded until after the Administrator completes the deductions under § 97.525 for the control period immediately before the year of such deadline.

(c) Where a TR NO X Ozone Season allowance transfer is not correctly submitted under § 97.522, the
Administrator will not record such
transfer. (d) Within 5 business days of
recordation of a TR NO X Ozone Season allowance transfer under paragraphs (a) and (b) of the section, the Administrator will notify the authorized account representatives of both the transferor
and transferee accounts.

(e) Within 10 business days of receipt
of a TR NO X Ozone Season allowance transfer that is not correctly submitted under § 97.522, the Administrator will notify the authorized account representatives of both accounts subject
to the transfer of:

(1) A decision not to record the transfer, and

(2) The reasons for such nonrecordation.

**§ 97.524 Compliance with TR NO** X **Ozone**
**Season emissions limitation.**

(a) Availability for deduction for compliance. TR NO X Ozone Season
allowances are available to be deducted for compliance with a source’s TR NO X Ozone Season emissions limitation for a control period in a given year only if the

TR NO X Ozone Season allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in the source’s compliance account as of the allowance
transfer deadline for such control period.

(b) Deductions for compliance. After the recordation, in accordance with § 97.523, of TR NO X Ozone Season allowance transfers submitted by the
allowance transfer deadline for a control period, the Administrator will deduct from the compliance account TR NO X Ozone Season allowances available under paragraph (a) of this section in
order to determine whether the source
meets the TR NO X Ozone Season
emissions limitation for such control period, as follows:

(1) Until the amount of TR NO X Ozone Season allowances deducted equals the number of tons of total NO X emissions from all TR NO X Ozone
Season units at the source for such control period; or

(2) If there are insufficient TR NO X Ozone Season allowances to complete the deductions in paragraph (b)(1) of this section, until no more TR NO X Ozone Season allowances available under paragraph (a) of this section remain in the compliance account.

(c)(1) Identification of TR NO X Ozone Season allowances by serial number. The authorized account representative for a source’s compliance account may request that specific TR NO X Ozone Season allowances, identified by serial number, in the compliance account be
deducted for emissions or excess emissions for a control period in


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accordance with paragraph (b) or (d) of this section. In order to be complete, such request shall be submitted to the Administrator by the allowance transfer deadline for such control period and include, in a format prescribed by the Administrator, the identification of the

TR NO X Ozone Season source and the appropriate serial numbers.

(2) First-in, first-out. The
Administrator will deduct TR NO X Ozone Season allowances under paragraph (b) or (d) of this section from the source’s compliance account in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the
case of identification of an insufficient
amount of TR NO X Ozone Season allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following order:

(i) Any TR NO X Ozone Season
allowances that were allocated to the
units at the source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR NO X Ozone Season allowances that were allocated to any
unit and transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in
which the TR NO X Ozone Season source has excess emissions, the Administrator
will deduct from the source’s compliance account an amount of TR

NO X Ozone Season allowances, allocated for the control period in the immediately following year, equal to
two times the number of tons of the

source’s excess emissions.

(e) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraphs (b) and (d) of this section.

**§ 97.525 Compliance with TR NO** X **Ozone Season assurance provisions.** 

(a) Availability for deduction. TR NO X Ozone Season allowances are available to be deducted for compliance with the

TR NO X Ozone Season assurance provisions for a control period in a given year by an owner of one or more

TR NO X Ozone Season units in a State only if the TR NO X Ozone Season
allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in a compliance account, designated by the owner in accordance with paragraph (b)(4)(ii) of this section,
of one of the owner’s TR NO X Ozone
Season sources in the State as of the deadline established in paragraph (b)(5)
of this section.

(b) Deductions for compliance. The
Administrator will deduct TR NO X Ozone Season allowances available under paragraph (a) of this section for compliance with the TR NO X Ozone Season assurance provisions for a State for a control period in a given year in accordance with the following procedures:

(1) By March 1, 2015 and March 1 of each year thereafter, the Administrator
will:

(i) Calculate, separately for each State,
the total amount of NO X emissions from
all TR NO X Ozone Season units in the State during the control period in the year before the year of this calculation deadline and the amount, if any, by
which such total amount of NO X emissions exceeds the State assurance level as described in § 97.506(c)(2)(iii);
and

(ii) Promulgate a notice of availability
of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations
of the NO X emissions for each TR NO X Ozone Season unit and of the amounts described in §§ 97.506(c)(2)(iii)(A) and (B) for each State.

(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of
this section.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each TR

NO X Ozone Season unit and each State for the control period in the year
involved are in accordance with § 97.506(c)(2)(iii) and §§ 97.506(b) and 97.530 through 97.535.

(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By May 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR NO X Ozone
Season sources with total NO X emissions exceeding the State assurance level for a control period, as described in § 97.506(c)(2)(iii):

(i) By May 15 immediately after the promulgation of such notice, the designated representative of each TR

NO X Ozone Season source in each such State shall submit a statement, in a format prescribed by the Administrator:

(A) Listing all the owners of each TR

NO X Ozone Season unit at the source, explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of

‘‘ owner ’’ in § 97.502, and listing, separately for each unit, the percentage of the legal, equitable, leasehold, or
contractual reservation or entitlement for each such owner as of midnight of December 31 of the control period in the year involved; and

(B) For each TR NO X Ozone Season unit at the source that operates during,
but is allocated no TR NO X Ozone Season allowances for, the control period in the year involved, identifying whether the unit is a coal-fired boiler, simple combustion turbine, or combined cycle turbine cycle and providing the unit’s allowable NO X emission rate for such control period.

(ii) By June 15 immediately after the promulgation of such notice, the Administrator will calculate, for each
such State and each owner of one or

more TR NO X Ozone Season units in the State and for the control period in the year involved, each owner’s share of the
total NO X emissions from all TR NO X Ozone Season units in the State, each owner’s assurance level, and the amount (if any) of TR NO X Ozone Season
allowances that each owner must hold
in accordance with the calculation formula in § 97.506(c)(2)(i) and will promulgate a notice of availability of the
results of these calculations.

(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability required in paragraph (b)(3)(ii) of this

section.

(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each owner for the control period in the year
involved are consistent with the NO X emissions for the relevant TR NO X Ozone Season units as set forth in the notice required in paragraph (b)(2)(ii) of this section, the definitions of ‘‘ owner ’’

,

‘‘ owner’s assurance level ’’ , and ‘‘ owner’s
share ’’ in § 97.502, and the calculation formula in § 97.506(c)(2)(i) and shall not raise any issues about any data used in the notice of data availability required in paragraph (b)(2)(ii) of this section.

(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section.


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By August 15 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that
the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(3)(iii)(A)
of this section.

(4) By September 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:

(i) Each owner identified, in such notice, as owning one or more TR NO X Ozone Season units in a State and as being required to hold TR NO X Ozone Season allowances shall designate the compliance account of one of the
sources at which such unit or units are located to hold such required TR NO X Ozone Season allowances;

(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.

(5)(i) As of midnight of September 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount
of TR NO X Ozone Season allowances, available for deduction under paragraph (a) of this section, equal to the amount the owner is required to hold as calculated by the Administrator and
referenced in such notice.

(ii) Notwithstanding the allowanceholding deadline specified in paragraph (b)(5)(i) of this section, if September 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day
thereafter.

(6) After September 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.523, of TR NO X Ozone Season allowance transfers submitted by midnight of such date, the
Administrator will deduct from each compliance account designated in accordance with paragraph (b)(4)(ii) of this section, TR NO X Ozone Season allowances available under paragraph (a) of this section, as follows:

(i) Until the amount of TR NO X Ozone Season allowances deducted equals the amount that the owner designating the compliance account is required to hold as calculated by the Administrator and referenced in the notice required in paragraph (b)(3)(iii)(B) of this section; or

(ii) If there are insufficient TR NO X Ozone Season allowances to complete the deductions in paragraph (b)(6)(i) of this section, until no more TR NO X Ozone Season allowances available under paragraph (a) of this section remain in the compliance account.

(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice,
the amount of TR NO X Ozone Season allowances that each owner is required
to hold in accordance with § 97.506(c)(2)(i) for the control period in the year involved shall continue to be such amount as calculated by the
Administrator and referenced in such notice required in paragraph (b)(3)(iii)(B) of this section, except as
follows:

(i) If any such data are revised by the
Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal
under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR NO X Ozone Season allowances that owners are required to hold in
accordance with the calculation formula in § 97.506(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that—

(A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and

(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section. (ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the
Administrator will use the data as so
revised to recalculate the amounts of TR

NO X Ozone Season allowances that owners are required to hold in
accordance with the calculation formula in § 97.506(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that such litigation was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii)(B) of
this section.

(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR NO X Ozone
Season allowances that an owner is required to hold for the control period in the year involved with regard to the
State involved-

(A) Where the amount of TR NO X Ozone Season allowances that an owner is required to hold increases as a result of the use of all such revised data, the Administrator will establish a new,
reasonable deadline on which the owner
shall hold the additional amount of TR

NO X Ozone Season allowances in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section. The owner’s failure to hold such additional amount, as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s failure to hold such additional amount, as required, as of the
new deadline shall be a violation of the
Clean Air Act. Each TR NO X Ozone
Season allowance that the owner fails to hold as required as of the new deadline, and each day in the control period in the year involved, shall be a separate
violation of the Clean Air Act. After such deadline, the Administrator will make the appropriate deductions from the compliance account.

(B) For an owner for which the
amount of TR NO X Ozone Season allowances required to be held
decreases as a result of the use of all such revised data, the Administrator will record, in the compliance account that the owner designated in accordance with paragraph (b)(4)(ii) of this section,
an amount of TR NO X Ozone Season allowances equal to the amount of the
decrease to the extent such amount was previously deducted from the compliance account under paragraph (b)(6) of this section (and has not already been restored to the compliance


### 45410 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

account) for the control period in the year involved.

(C) Each TR NO X Ozone Season
allowance held and deducted under paragraph (b)(7)(iii)(A) of this section, or recorded under paragraph (b)(7)(iii)(B) of this section, as a result of recalculation of requirements for compliance with the TR NO X Ozone Season assurance provisions for a control period in a given year must be

a TR NO X Ozone Season allowance allocated for a control period in the same or a prior year.

(c)(1) Identification of TR NO X Ozone Season allowances by serial number. The authorized account representative for each source’s compliance account designated in accordance with paragraph (b)(4)(ii) of this section may request that specific TR NO X Ozone Season allowances, identified by serial number, in the compliance account be deducted in accordance with paragraph (b)(6) or (7) of this section. In order to be complete, such request shall be submitted to the Administrator by the allowance-holding deadline described in paragraph (b)(5) of this section and include, in a format prescribed by the Administrator, the identification of the compliance account and the appropriate
serial numbers.

(2) First-in, first-out. The
Administrator will deduct TR NO X Ozone Season allowances under paragraphs (b)(6) and (7) of this section from each source’s compliance account designated under paragraph (b)(4)(ii) of
this section in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the case of identification
of an insufficient amount of TR NO X Ozone Season allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following order:

(i) Any TR NO X Ozone Season
allowances that were allocated to the
units at the source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR NO X Ozone Season allowances that were allocated to any
unit and transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraph (b) of this section.

**§ 97.526 Banking.**

(a) A TR NO X Ozone Season allowance may be banked for future use or transfer in a compliance account or a general account in accordance with paragraph (b) of this section. (b) Any TR NO X Ozone Season allowance that is held in a compliance account or a general account will
remain in such account unless and until
the TR NO X Ozone Season allowance is
deducted or transferred under § 97.511(c), § 97.523, § 97.524, § 97.525,

97.527, 97.528, 97.542, or 97.543.

**§ 97.527 Account error.**

The Administrator may, at his or her
sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.

**§ 97.528 Administrator’s action on**
**submissions.**

(a) The Administrator may review and conduct independent audits concerning any submission under the TR NO X Ozone Season Trading Program and make appropriate adjustments of the
information in the submission.

(b) The Administrator may deduct TR

NO X Ozone Season allowances from or
transfer TR NO X Ozone Season allowances to a source’s compliance
account based on the information in a submission, as adjusted under paragraph (a)(1) of this section, and
record such deductions and transfers.

**§ 97.529 [Reserved]**

**§ 97.530 General monitoring, recordkeeping, and reporting requirements.** 

The owners and operators, and to the extent applicable, the designated representative, of a TR NO X Ozone Season unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subpart H of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.502 and in § 72.2 of this chapter shall apply, the terms ‘‘ affected unit, ’’

‘‘ designated representative, ’’ and

‘‘ continuous emission monitoring system ’’ (or ‘‘ CEMS ’’ ) in part 75 of this chapter shall be deemed to refer to the

terms ‘‘ TR NO X Ozone Season unit, ’’

‘‘ designated representative, ’’ and

‘‘ continuous emission monitoring system ’’ (or ‘‘ CEMS ’’ ) respectively as defined in § 97.502, and the term ‘‘ newly
affected unit ’’ shall be deemed to mean

‘‘ newly affected TR NO X Ozone Season

unit ’’ . The owner or operator of a unit
that is not a TR NO X Ozone Season unit
but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a TR NO X Ozone

Season unit. (a) Requirements for installation, certification, and data accounting. The owner or operator of each TR NO X Ozone Season unit shall:

(1) Install all monitoring systems required under this subpart for monitoring NO X mass emissions and individual unit heat input (including all systems required to monitor NO X emission rate, NO X concentration, stack gas moisture content, stack gas flow rate, CO 2 or O 2 concentration, and fuel flow rate, as applicable, in accordance with §§ 75.71 and 75.72 of this chapter);

(2) Successfully complete all certification tests required under § 97.531 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator shall meet the monitoring system certification and other requirements of paragraphs (a)(1) and (2) of this section on or before the following dates. The owner or operator shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.

(1) For the owner or operator of a TR

NO X Ozone Season unit that commences commercial operation before July 1, 2011, by May 1, 2012.

(2) For the owner or operator of a TR

NO X Ozone Season unit that commences commercial operation on or after July 1, 2011 and that reports on an annual basis under § 97.534(d), by the later of the following dates:

(i) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation;

or (ii) May 1, 2012.

(3) For the owner or operator of a TR

NO X Ozone Season unit that commences commercial operation on or after July 1, 2011 and that reports on a control period basis under § 97.534(d)(2)(ii), by the later of the following dates:

(i) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation;

or (ii) If the compliance date under paragraph (b)(3)(i) of this section is not during a control period, May 1 immediately after the compliance date under paragraph (b)(3)(i) of this section.

(4) For the owner or operator of a TR

NO X Ozone Season unit for which


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construction of a new stack or flue or
installation of add-on NO X emission controls is completed after the applicable deadline under paragraph (b)(1) or (2) of this section and that reports on an annual basis under § 97.534(d), by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which emissions first exit to the atmosphere through the
new stack or flue or add-on NO X emissions controls.

(5) For the owner or operator of a TR

NO X Ozone Season unit for which
construction of a new stack or flue or
installation of add-on NO X emission controls is completed after the applicable deadline under paragraph (b)(1) or (3) of this section and that reports on a control period basis under § 97.534(d)(2)(ii), by the later of the following dates:

(i) 90 unit operating days or 180 calendar days, whichever occurs first,
after the date on which emissions first exit to the atmosphere through the new
stack or flue or add-on NO X emissions controls; or

(ii) If the compliance date under paragraph (b)(5)(i) of this section is not during a control period, May 1 immediately after the compliance date under paragraph (b)(5)(i) of this section.

(6) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of this section, for the owner or operator of a unit for which a TR opt-in application
is submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.541(c).

(7) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of this section, for the owner or operator of a

TR NO X Ozone Season opt-in unit, by
the date on which the TR NO X Annual opt-in unit enters the TR NO X Ozone Season Trading Program as provided in § 97.541(h).

(c) Reporting data. The owner or operator of a TR NO X Ozone Season unit that does not meet the applicable compliance date set forth in paragraph (b) of this section for any monitoring system under paragraph (a)(1) of this section shall, for each such monitoring system, determine, record, and report maximum potential (or, as appropriate, minimum potential) values for NO X concentration, NO X emission rate, stack gas flow rate, stack gas moisture content, fuel flow rate, and any other parameters required to determine NO X mass emissions and heat input in accordance with § 75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 75 of this chapter, or section 2.5 of appendix E to part 75 of this chapter, as applicable. (d) Prohibitions. (1) No owner or operator of a TR NO X Ozone Season unit shall use any alternative monitoring system, alternative reference method, or any other alternative to any requirement of this subpart without having obtained prior written approval in accordance with § 97.535.

(2) No owner or operator of a TR NO X Ozone Season unit shall operate the unit so as to discharge, or allow to be discharged, NO X emissions to the atmosphere without accounting for all
such emissions in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(3) No owner or operator of a TR NO X Ozone Season unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording NO X mass emissions discharged into the atmosphere or heat input, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(4) No owner or operator of a TR NO X Ozone Season unit shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, or any other approved monitoring system under this subpart, except under any one of the following circumstances:

(i) During the period that the unit is covered by an exemption under § 97.505 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the
Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or

(iii) The designated representative
submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.531(d)(3)(i).

(e) Long-term cold storage. The owner or operator of a TR NO X Ozone Season unit is subject to the applicable provisions of § 75.4(d) of this chapter concerning units in long-term cold storage.

**§ 97.531 Initial monitoring system certification and recertification procedures.** 

(a) The owner or operator of a TR NO X Ozone Season unit shall be exempt from the initial certification requirements of this section for a monitoring system under § 97.530(a)(1) if the following
conditions are met:

(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and

(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of
this section.

(b) The recertification provisions of this section shall apply to a monitoring system under § 97.530(a)(1) exempt from initial certification requirements under paragraph (a) of this section.

(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the

NO X emission rate measured in a common stack or a petition under § 75.66 of this chapter for an alternative to a requirement in § 75.12 or § 75.17 of this chapter, the designated representative shall resubmit the petition to the Administrator under § 97.535 to determine whether the approval applies under the TR NO X Ozone Season Trading Program.

(d) Except as provided in paragraph (a) of this section, the owner or operator
of a TR NO X Ozone Season unit shall comply with the following initial
certification and recertification procedures for a continuous monitoring system ( i.e., a continuous emission monitoring system and an excepted monitoring system under appendices D and E to part 75 of this chapter) under § 97.530(a)(1). The owner or operator of a unit that qualifies to use the low mass emissions excepted monitoring methodology under § 75.19 of this chapter or that qualifies to use an alternative monitoring system under subpart E of part 75 of this chapter shall comply with the procedures in paragraph (e) or (f) of this section respectively.

(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under § 97.530(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.530(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.


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(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.530(a)(1) that may significantly affect the ability of the system to accurately measure or
record NO X mass emissions or heatinput rate or to meet the qualityassurance and quality-control requirements of § 75.21 of this chapter or appendix B to part 75 of this chapter, the owner or operator shall recertify the monitoring system in accordance with § 75.20(b) of this chapter. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit’s operation that may significantly change the stack flow or concentration profile, the owner or operator shall recertify each continuous emission monitoring system whose accuracy is potentially affected by the change, in accordance with § 75.20(b) of this chapter. Examples of changes to a continuous emission monitoring system that require recertification include: Replacement of the analyzer, complete replacement of an existing continuous emission monitoring system, or change
in location or orientation of the sampling probe or site. Any fuel flowmeter systems, and any excepted

NO X monitoring system under appendix E to part 75 of this chapter, under § 97.530(a)(1) are subject to the recertification requirements in § 75.20(g)(6) of this chapter.

(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.530(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words

‘‘ certification ’’ and ‘‘ initial certification ’’ are replaced by the word

‘‘ recertification ’’ and the word ‘‘ certified ’’ is replaced by with the word

‘‘ recertified ’’

.

(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office
and the Administrator written notice of the dates of certification testing, in accordance with § 97.533.

(ii) Certification application. The designated representative shall submit
to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.

(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under
the TR NO X Ozone Season Trading Program for a period not to exceed 120 days after receipt by the Administrator of the complete certification application for the monitoring system under paragraph (d)(3)(ii) of this section. Data measured and recorded by the provisionally certified monitoring system, in accordance with the requirements of part 75 of this chapter, will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that
the Administrator does not invalidate the provisional certification by issuing a notice of disapproval within 120 days of the date of receipt of the complete certification application by the
Administrator.

(iv) Certification application approval

process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter
and is included in the certification application will be deemed certified for
use under the TR NO X Ozone Season Trading Program.

(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter,
then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day review period specified in paragraph (d)(3) of this section shall not begin before receipt of a complete certification application.

(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).

(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of
a monitor in accordance with § 97.532(b).

(v) Procedures for loss of certification.
If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section,
then:

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NO X emission rate ( i.e., NO X -diluent) system, the maximum potential NO X emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NO X pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of

NO X and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO 2 concentration or the minimum potential O 2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel


### 45413 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NO X monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NO X emission rate, as defined in § 72.2 of this chapter.

(B) The designated representative
shall submit a notification of
certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this

section.

(C) The owner or operator shall repeat
all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days
after the date of issuance of the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the
certification and recertification requirements in § 75.20(g) of this chapter.

(f) The designated representative of
each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.

**§ 97.532 Monitoring system out-of-control periods.** 

( a ) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.

( b ) Audit decertification. Whenever both an audit of a monitoring system
and a review of the initial certification or recertification application reveal that any monitoring system should not have
been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.531 or the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit
shall be either a field audit or an audit of any information submitted to the Administrator or any permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data
from the date of issuance of the
notification of the revoked certification
status until the date and time that the owner or operator completes subsequently approved initial
certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable
initial certification or recertification procedures in § 97.531 for each disapproved monitoring system.

**§ 97.533 Notifications concerning monitoring.** 

The designated representative of a TR

NO X Ozone Season unit shall submit
written notice to the Administrator in accordance with § 75.61 of this chapter.

**§ 97.534 Recordkeeping and reporting.**

( a ) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.514(a).

( b ) Monitoring plans. The owner or operator of a TR NO X Ozone Season unit shall comply with requirements of § 75.73(c) and (e) of this chapter.

( c ) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all
initial certification or recertification tests required under § 97.531, including the information required under § 75.63 of this chapter.

( d ) Quarterly reports. The designated representative shall submit quarterly reports, as follows:

(1) If the TR NO X Ozone Season unit is subject to the Acid Rain Program or

a TR NO X Annual emissions limitation or if the owner or operator of such unit chooses to report on an annual basis under this subpart, the designated representative shall meet the requirements of subpart H of part 75 of this chapter (concerning monitoring of

NO X mass emissions) for such unit for the entire year and shall report the NO X mass emissions data and heat input data for such unit, in an electronic quarterly report in a format prescribed by the Administrator, for each calendar quarter beginning with:

(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering May 1, 2012 through June 30, 2012;

(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.530(b), unless that quarter is the third or fourth quarter of 2011 or the first quarter of 2012, in which case reporting shall commence in the quarter covering May 1, 2012 through June 30, 2012;

(2) If the TR NO X Ozone Season unit is not subject to the Acid Rain Program

or a TR NO X Annual emissions limitation, then the designated representative shall either:

(i) Meet the requirements of subpart H of part 75 (concerning monitoring of

NO X mass emissions) for such unit for the entire year and report the NO X mass emissions data and heat input data for such unit in accordance with paragraph (d)(1) of this section; or

(ii) Meet the requirements of subpart H of part 75 for the control period (including the requirements in § 75.74(c) of this chapter) and report

NO X mass emissions data and heat input data (including the data described in § 75.74(c)(6) of this chapter) for such unit only for the control period of each year and report, in an electronic quarterly report in a format prescribed by the Administrator, for each calendar quarter beginning with:

(A) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering May 1, 2012 through June 30, 2012;

(B) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.530(b), unless that date is not during a control period, in which case reporting shall commence in the quarter that includes May 1 through June 30 of the first control period after such date;

(3) Notwithstanding paragraphs (d)(1) and (2) of this section, for a unit for which a TR opt-in application is
submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.541(c); and

(4) Notwithstanding paragraphs (d)(1) and (2) of this section, for a TR NO X


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Ozone Season opt-in unit, the calendar quarter corresponding to the date on
which the TR NO X Annual opt-in unit
enters the TR NO X Ozone Season Trading Program as provided in § 97.541(h).

(5) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.

(6) For TR NO X Ozone Season units that are also subject to the Acid Rain Program, TR NO X Annual Trading Program, TR SO 2 Group 1 Trading Program, or TR SO 2 Group 1 Trading Program, quarterly reports shall include the applicable data and information required by subparts F through H of part 75 of this chapter as applicable, in
addition to the NO X mass emission data, heat input data, and other information required by this subpart.

(7) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.

(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any
corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.

(8) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(5) of
this section.

( e ) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully
monitored. The certification shall state
that:

(1) The monitoring data submitted
were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications;

(2) For a unit with add-on NO X emission controls and for all hours
where NO X data are substituted in accordance with § 75.34(a)(1) of this chapter, the add-on emission controls were operating within the range of parameters listed in the quality assurance/quality control program under appendix B to part 75 of this chapter and the substitute data values do not systematically underestimate

NO X emissions; and

(3) For a unit that is reporting on a control period basis under paragraph (d)(2)(ii) of this section, the NO X emission rate and NO X concentration values substituted for missing data under subpart D of part 75 of this chapter are calculated using only values from a control period and do not systematically underestimate NO X emissions.

**§ 97.535 Petitions for alternatives to monitoring, recordkeeping, or reporting**  **requirements.**

(a) The designated representative of a

TR NO X Ozone Season unit may submit a petition under § 75.66 of this chapter to the Administrator, requesting approval to apply an alternative to any requirement of §§ 97.530 through 97.534 or paragraph (5)(i) or (ii) of the
definition of ‘‘ owner’s share ’’ in § 97.502.

(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition, including, at a minimum, the following information:

(i) Identification of each unit and source covered by the petition;

(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;

(iii) A description and diagram of any equipment and procedures used in the proposed alternative;

(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the
alternative will be de minimis; and

(v) Any other relevant information that the Administrator may require.

(c) Use of an alternative to any requirement referenced in paragraph (a)
of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.

**§ 97.540 General requirements for TR NO** X **Ozone Season opt-in units.**

(a) A TR NO X Ozone Season opt-in
unit must be a unit that:

(1) Is located in a State; (2) Is not a TR NO X Ozone Season unit under § 97.504;

(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and

(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.

(b) A TR NO X Ozone Season opt-in
unit shall be deemed to be a TR NO X Ozone Season unit for purposes of applying this subpart, except for §§ 97.505, 97.511, and 97.512.

(c) Solely for purposes of applying the requirements of §§ 97.513 through 97.518 and §§ 97.530 through 97.535, a unit for which a TR opt-in application
is submitted and not withdrawn and is not yet approved or disapproved under § 97.542 shall be deemed to be a TR

NO X Ozone Season unit.

(d) Any TR NO X Ozone Season opt-inunit, and any unit for which a TR optin application is submitted and not withdrawn and is not yet approved or disapproved under § 97.542, located at
the same source as one or more TR NO X Ozone Season units shall have the same designated representative and alternate designated representative as such TR

NO X Ozone Season units.

**§ 97.541 Opt-in process.**

A unit meeting the requirements for a

TR NO X Ozone Season opt-in unit in § 97.540(a) may become a TR NO X Ozone Season opt-in unit only if, in accordance with this section, the designated representative of the unit submits a complete TR opt-in application for the unit and the Administrator approves the application.

(a) Applying to opt-in. The designated representative of the unit may submit a complete TR opt-in application for the unit at any time, except as provided under § 97.542(e). A complete TR opt-in application shall include the following elements in a format prescribed by the
Administrator:

(1) Identification of the unit and the source where the unit is located,


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including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, and unit identification number and type;

(2) A certification that the unit: (i) Is not a TR NO X Ozone Season unit under § 97.504;

(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;

(iii) Vents all of its emissions to a stack; and

(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;

(3) A monitoring plan in accordance with §§ 97.530 through 97.535;

(4) A statement that the unit, if approved to become a TR NO X Ozone Season unit under paragraph (g) of this section, may withdraw from the TR NO X Ozone Season Trading Program only in accordance with § 97.542;

(5) A statement that the unit, if approved to become a TR NO X Ozone Season unit under paragraph (g) of this section, is subject to, and the owners and operators of the unit must comply with, the requirements of § 97.543;

(6) A complete certificate of representation under § 97.516 consistent with § 97.540, if no designated representative has been previously designated for the source that includes the unit; and

(7) The signature of the designated representative and the date signed.

(b) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan submitted under paragraph (a)(3) of this section. The monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the NO X emission rate and heat input of the unit and all other applicable parameters are monitored and reported in accordance with §§ 97.530 through 97.535. A determination of sufficiency shall not be construed as acceptance or approval of the monitoring plan.

(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the monitoring plan is sufficient under paragraph (b) of this section, the owner or operator of the unit shall monitor and report the NO X emission rate and the heat input of the unit and all other applicable parameters, in accordance with §§ 97.530 through 97.535, starting
on the date of certification of the necessary monitoring systems under §§ 97.530 through 97.535 and continuing until the TR opt-in application submitted under paragraph (a) of this section is disapproved under this section or, if such TR opt-in application is approved, the date and
time when the unit is withdrawn from
the TR NO X Ozone Season Trading Program in accordance with § 97.542.

(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which
the unit enters the TR NO X Ozone Season Trading Program under paragraph (h) of this section, during which period monitoring system availability must not be less than 98 percent under §§ 97.530 through 97.535 and the unit must be in full compliance with any applicable State or Federal
emissions or emissions-related requirements.

(2) To the extent the NO X emissions rate and the heat input of the unit are monitored and reported in accordance with §§ 97.530 through 97.535 for one or more entire control periods, in addition to the control period under paragraph (c)(1)(ii) of this section, during which control periods monitoring system availability is not less than 98 percent under §§ 97.530 through 97.535 and the unit is in full compliance with any applicable State or Federal emissions or emissions-related requirements and which control periods begin not more than 3 years before the unit enters the

TR NO X Ozone Season Trading Program under paragraph (h) of this section, such information shall be used as provided in paragraphs (e) and (f) of this section.

(d) Statement on compliance. After submitting to the Administrator all quarterly reports required for the unit under paragraph (c) of this section, the designated representative shall submit, in a format prescribed by the Administrator, to the Administrator a statement that, for the years covered by such quarterly reports, the unit was in full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.

(e) Baseline heat input. The unit’s baseline heat input shall equal:

(1) If the unit’s NO X emissions rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s total heat input (in mmBtu) for such control period; or

(2) If the unit’s NO X emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, the average of the amounts of the unit’s total heat input (in mmBtu) for such control periods. (f) Baseline NO X emission rate. The
unit’s baseline NO X emission rate shall equal:

(1) If the unit’s NO X emission rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s NO X emission rate (in lb/mmBtu) for such control period;

(2) If the unit’s NO X emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of thissection, and the unit does not have addon NO X emission controls during any such control periods, the average of the
amounts of the unit’s NO X emission rate (in lb/mmBtu) for such control periods;

or (3) If the unit’s NO X emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, and the unit has add-on NO X emission controls during any such control periods, the average of the
amounts of the unit’s NO X emission rate (in lb/mmBtu) for such control periods during which the unit has add-on NO X emission controls.

(g) Review of TR opt-in application. (1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the
Administrator determines that the designated representative shows that the unit meets the requirements for a TR

NO X Ozone Season opt-in unit in § 97.540, the element certified in paragraph (a)(2)(iv) of this section, and the monitoring and reporting requirements of paragraph (c) of this section, the Administrator will issue a written approval of the TR opt-in application for the unit. The written approve will state the unit’s baseline heat input and baseline NO X emission
rate. The Administrator will thereafter establish a compliance account for the
source that includes the unit unless the source already has a compliance

account.

(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines
that the unit cannot meet the requirements for a TR NO X Ozone Season opt-in unit in § 97.540, the element certified in paragraph (a)(2)(iv) of this section, or the monitoring and reporting requirements in paragraph (c) of this section, the Administrator will issue a written disapproval of the TR opt-in application for the unit.


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(h) Date of entry into TR NO X Ozone Season Trading Program. A unit for which a TR opt-in application is approved under paragraph (g)(1) of this
section shall become a TR NO X Ozone Season opt-in unit, and a TR NO X Ozone Season unit, effective as of the later of May 1, 2012 or May 1 of the first control period during which such approval is issued.

**§ 97.542 Withdrawal of TR NO** X **Ozone Season opt-in unit from TR NO**  X **Ozone Season Trading Program.** 

A TR NO X Ozone Season opt-in unit may withdraw from the TR NO X Ozone Season Trading Program only if, in accordance with this section, the designated representative of the unit submits a request to withdraw the unit
and the Administrator issues a written approval of the request.

(a) Requesting withdrawal. In order to
withdraw the TR NO X Ozone Season opt-in unit from the TR NO X Ozone Season Trading Program, the designated representative of the unit shall submit to the Administrator a request to withdraw the unit effective as of midnight of September 30 of a specified calendar year, which date must be at least 4 years after September 30 of the year of the unit’s entry into the TR NO X Ozone Season Trading Program under § 97.541(h). The request shall be in a format prescribed by the Administrator
and shall be submitted no later than 90 days before the requested effective date
of withdrawal.

(b) Conditions for withdrawal. Before

a TR NO X Ozone Season opt-in unit covered by the request to withdraw may
withdraw from the TR NO X Ozone Season Trading Program, the following
conditions must be met:

(1) For the control period ending on
the date on which the withdrawal is to be effective, the source that includes the

TR NO X Ozone Season opt-in unit must meet the requirement to hold TR NO X Ozone Season allowances under §§ 97.524 and 97.525 and cannot have any excess emissions.

(2) After the requirement under paragraph (b)(1) of this section is met,
the Administrator will deduct from the compliance account of the source that
includes the TR NO X Ozone Season optin unit TR NO X Ozone Season allowances equal in amount to and allocated for the same or a prior control period as any TR NO X Ozone Season
allowances allocated to the TR NO X Ozone Season opt-in unit under § 97.544 for any control period after the
date on which the withdrawal is to be
effective. If there are no other TR NO X Ozone Season units at the source, the Administrator will close the compliance account, and the owners and operators
of the TR NO X Ozone Season opt-in unit may submit a TR NO X Ozone Season allowance transfer for any remaining TR

NO X Ozone Season allowances to another Allowance Management System account in accordance §§ 97.522 and

97.523.

(c) Approving withdrawal. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full
amount of TR NO X Ozone Season allowances required), the Administrator will issue a written approval of the request to withdraw, which will become effective as of midnight on September 30 of the calendar year for which the withdrawal was requested. The unit covered by the request shall continue to
be a TR NO X Ozone Season opt-in unit
until the effective date of the withdrawal and shall comply with all requirements under the TR NO X Ozone Season Trading Program concerning any control periods for which the unit is a

TR NO X Ozone Season opt-in unit, even if such requirements arise or must be complied with after the withdrawal
takes effect.

(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR

NO X Ozone Season opt-in unit.

(d) Reapplication upon failure to meet conditions of withdrawal. If the Administrator disapproves the request to withdraw, the designated representative of the unit may submit another request to withdraw in accordance with paragraphs (a) and (b)
of this section.

(e) Ability to reapply to the TR NO X Ozone Season Trading Program. Once a

TR NO X Ozone Season opt-in unit
withdraws from the TR NO X Ozone Season Trading Program, the designated representative may not submit another opt-in application under § 97.541 for such unit before the date that is 4 years
after the date on which the withdrawal
became effective.

**§ 97.543 Change in regulatory status.**

(a) Notification. If a TR NO X Ozone Season opt-in unit becomes a TR NO X Ozone Season unit under § 97.504, then the designated representative of the unit shall notify the Administrator in writing of such change in the TR NO X Ozone Season opt-in unit’s regulatory status, within 30 days of such change.

(b) Administrator’s actions. (1) If a TR

NO X Ozone Season opt-in unit becomes

a TR NO X Ozone Season unit under § 97.504, the Administrator will deduct, from the compliance account of the
source that includes the TR NO X Ozone Season opt-in unit that becomes a TR

NO X Ozone Season unit under § 97.504,

TR NO X Ozone Season allowances equal
in amount to and allocated for the same or a prior control period as:

(i) Any TR NO X Ozone Season
allowances allocated to the TR NO X Ozone Season opt-in unit under § 97.544 for any control period starting
after the date on which the TR NO X Ozone Season opt-in unit becomes a TR

NO X Ozone Season unit under § 97.504;
and

(ii) If the date on which the TR NO X Ozone Season opt-in unit becomes a TR

NO X Ozone Season unit under § 97.504 is not September 30, the TR NO X Ozone
Season allowances allocated to the TR

NO X Ozone Season opt-in unit under § 97.544 for the control period that
includes the date on which the TR NO X Ozone Season opt-in unit becomes a TR

NO X Ozone Season unit under § 97.504—

(A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

NO X Ozone Season opt-in unit becomes

a TR NO X Ozone Season unit under § 97.504, divided by the total number of days in the control period, and

(B) Rounded to the nearest allowance. (2) The designated representative shall ensure that the compliance
account of the source that includes the

TR NO X Ozone Season opt-in unit that
becomes a TR NO X Ozone Season unit under § 97.504 contains the TR NO X Ozone Season allowances necessary for completion of the deduction under paragraph (b)(1) of this section.

(3)(i) For control periods starting after
the date on which the TR NO X Ozone Season opt-in unit becomes a TR NO X Ozone Season unit under § 97.504, the

TR NO X Ozone Season opt-in unit will
be allocated TR NO X Ozone Season allowances in accordance with § 97.512.

(ii) If the date on which the TR NO X Ozone Season opt-in unit becomes a TR

NO X Ozone Season unit under § 97.504 is not September 30, the following
amount of TR NO X Ozone Season
allowances will be allocated to the TR

NO X Ozone Season opt-in unit (as a TR

NO X Ozone Season unit) in accordance with § 97.512 for the control period that
includes the date on which the TR NO X Ozone Season opt-in unit becomes a TR

NO X Ozone Season unit under § 97.504:

(A) The amount of TR NO X Ozone
Season allowances otherwise allocated
to the TR NO X Ozone Season opt-in unit (as a TR NO X Ozone Season unit) in accordance with § 97.512 for the control period;


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(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

NO X Ozone Season opt-in unit becomes

a TR NO X Ozone Season unit under § 97.504, divided by the total number of days in the control period; and

(C) Rounded to the nearest allowance.

**§ 97.544 TR NO** X **Ozone Season allowance**
**allocations to TR NO** X **Ozone Season opt-in**

**units.**

(a) Timing requirements. (1) When the TR opt-in application is approved for a unit under § 97.541(g), the
Administrator will issue TR NO X Ozone
Season allowances and allocate them to the unit for the control period in which
the unit enters the TR NO X Ozone Season Trading Program under § 97.541(h), in accordance with paragraph (b) of this section.

(2) By no later than July 30 of the control period after the control period in
which a TR NO X Ozone Season opt-in
unit enters the TR NO X Ozone Season Trading Program under § 97.541(h) and July 30 of each year thereafter, the
Administrator will issue TR NO X Ozone
Season allowances and allocate them to
the TR NO X Ozone Season opt-in unit for the control period that includes such
allocation deadline and in which the

unit is a TR NO X Ozone Season opt-in unit, in accordance with paragraph (b)
of this section.

(b) Calculation of allocation. For each control period for which a TR NO X Ozone Season opt-in unit is to be
allocated TR NO X Ozone Season allowances, the Administrator will issue
and allocate TR NO X Ozone Season
allowances in accordance with the following procedures:

(1) The heat input (in mmBtu) used for calculating the TR NO X Ozone
Season allowance allocation will be the
lesser of:

(i) The TR NO X Ozone Season opt-in unit’s baseline heat input determined under § 97.541(g); or

(ii) The TR NO X Ozone Season opt-in unit’s heat input, as determined in accordance with §§ 97.530 through 97.535, for the immediately prior control period, except when the allocation is being calculated for the control period in which the TR NO X Ozone Season opt-in unit enters the TR

NO X Ozone Season Trading Program under § 97.541(h).

(2) The NO X emission rate (in lb/ mmBtu) used for calculating TR NO X Ozone Season allowance allocations
will be the lesser of:

(i) The TR NO X Ozone Season opt-in
unit’s baseline NO X emission rate (in lb/ mmBtu) determined under § 97.541(g) and multiplied by 70 percent; or (ii) The most stringent State or
Federal NO X emissions limitation applicable to the TR NO X Ozone Season opt-in unit at any time during the control period for which TR NO X Ozone
Season allowances are to be allocated.

(3) The Administrator will issue TR

NO X Ozone Season allowances and
allocate them to the TR NO X Ozone Season opt-in unit in an amount equaling the heat input under paragraph (b)(1) of this section, multiplied by the

NO X emission rate under paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded to the nearest
allowance.

(c) Recordation. (1) The Administrator will record, in the compliance account
of the source that includes the TR NO X Ozone Season opt-in unit, the TR NO X Ozone Season allowances allocated to
the TR NO X Ozone Season opt-in unit under paragraph (a)(1) of this section.

(2) By September 1 of the control period after the control period in which

a TR NO X Ozone Season opt-in unit
enters the TR NO X Ozone Season Trading Program under § 97.541(h) and September 1 of each year thereafter, the Administrator will record, in the compliance account of the source that
includes the TR NO X Ozone Season optin unit, the TR NO X Ozone Season
allowances allocated to the TR NO X Ozone Season opt-in unit under paragraph (a)(2) of this section.

37. Part 97 is amended by adding subpart CCCCC to read as follows:

**Subpart CCCCC—TR SO** 2 **Group 1 Trading Program** 

Sec. 97.601 Purpose.
97.602 Definitions. 97.603 Measurements, abbreviations, and

acronyms. 97.604 Applicability. 97.605 Retired unit exemption. 97.606 Standard requirements. 97.607 Computation of time. 97.608 Administrative appeal procedures. 97.609 [Reserved]

97.610 State SO 2 Group 1 trading budgets, new-unit set- asides, and variability
limits. 97.611 Timing requirements for TR SO 2 Group 1 allowance allocations.

97.612 TR SO 2 Group 1 allowance
allocations for new units. 97.613 Authorization of designated representative and alternate designated representative. 97.614 Responsibilities of designated representative and alternate designated representative. 97.615 Changing designated representative and alternate designated representative; changes in owners and operators. 97.616 Certificate of representation. 97.617 Objections concerning designated representative and alternate designated representative. 97.618 Delegation by designated representative and alternate designated representative. 97.619 [Reserved]
97.620 Establishment of Allowance Management System accounts.
97.621 Recordation of TR SO 2 Group 1
allowance allocations.
97.622 Submission of TR SO 2 Group 1
allowance transfers.
97.623 Recordation of TR SO 2 Group 1
allowance transfers. 97.624 Compliance with TR SO 2 Group 1
emissions limitation. 97.625 Compliance with TR SO 2 Group 1 assurance provisions. 97.626 Banking.

97.627 Account error.
97.628 Administrator’s action on
submissions. 97.629 [Reserved] 97.630 General monitoring, recordkeeping, and reporting requirements. 97.631 Initial monitoring system
certification and recertification procedures. 97.632 Monitoring system out-of-control periods. 97.633 Notifications concerning monitoring. 97.634 Recordkeeping and reporting.
97.635 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements. 97.640 General requirements for TR SO 2 Group 1 opt-in units. 97.641 Opt-in process.
97.642 Withdrawal of TR SO 2 Group 1 optin unit from TR SO 2 Group 1 Trading Program. 97.643 Change in regulatory status.

97.644 TR SO 2 Group 1 allowance
allocations to TR SO 2 Group 1 opt-in

units.

**Subpart CCCCC—TR SO** 2 **Group 1 Trading Program** 

**§ 97.601 Purpose.**

This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) SO 2 Group 1 Trading Program, under section 110 of the Clean Air Act and § 52.38(b) of this chapter, as a means of mitigating interstate transport of fine particulates and nitrogen oxides.

**§ 97.602 Definitions.**

The terms used in this subpart shall have the meanings set forth in this
section as follows:

Acid Rain Program means a multistate SO 2 and NO X air pollution control and emission reduction program established by the Administrator under title IV of the Clean Air Act and parts 72 through 78 of this chapter.

Administrator means the
Administrator of the United States Environmental Protection Agency or the
Director of the Clean Air Markets Division (or its successor) of the United


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States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.

Allocate or allocation means, with regard to TR SO 2 Group 1 allowances, the determination by the Administrator
of the amount of such TR SO 2 Group 1 allowances to be initially credited to a

TR SO 2 Group 1 source or a new unit
set-aside.

Allowable SO 2 emission rate means, with regard to a unit, the SO 2 emission rate limit that is applicable to the unit and covers the longest averaging period not exceeding one year.

Allowance Management System means the system by which the Administrator records allocations, deductions, and transfers of TR SO 2 Group 1 allowances under the TR SO 2 Group 1 Trading Program. Such allowances are allocated, held, deducted, or transferred only as whole
allowances. The Allowance Management System is a component of the CAMD Business System, which is the system used by the Administrator to
handle TR SO 2 Group 1 allowances and
data related to SO 2 emissions.

Allowance Management System

account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, holding, transfer, or deduction of TR

SO 2 Group 1 allowances.

Allowance transfer deadline means, for a control period, midnight of March 1 (if it is a business day), or midnight of the first business day thereafter (if March 1 is not a business day), immediately after such control period and is the deadline by which a TR SO 2 Group 1 allowance transfer must be
submitted for recordation in a TR SO 2 Group 1 source’s compliance account in
order to be available for use in complying with the source’s TR SO 2 Group 1 Annual emissions limitation for such control period in accordance with § 97.624.

Alternate designated representative means, for a TR SO 2 Group 1 source and
each TR SO 2 Group 1 unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with this subpart, to act on behalf of the designated representative in matters pertaining to the TR SO 2 Group 1 Trading Program. If the TR SO 2 Group 1 source is also subject to the Acid Rain Program, TR NO X Annual Season Trading Program, or TR NO X Ozone Season Trading Program, then this natural person shall be the same natural person as the alternate designated representative as defined in § 72.2 of this chapter, § 97.402, or § 97.502 respectively.

Authorized account representative means, with regard to a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of TR SO 2 Group 1 allowances held in the general account and, with regard to a TR SO 2 Group 1 source’s compliance account, the designated representative of the

source.

Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a
continuous record of the measured parameters in the measurement units required by this subpart.

Biomass means— (1) Any organic material grown for the purpose of being converted to energy;

(2) Any organic byproduct of agriculture that can be converted into

energy; or

(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from
other material that is nonmerchantable for other purposes, and that is;

(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct
from conversion of trees to merchantable material; or

(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.

Boiler means an enclosed fossil- or
other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other
medium.

Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

Certifying official means a natural person who is:

(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation; (2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or

(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking
elected official.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.

Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.

Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

Coal-fired means combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during 1990 or any year thereafter.

Cogeneration system means an integrated group, at a source, of equipment (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 electricity through the sequential use of energy.

Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine—

(1) Operating as part of a cogeneration system; and

(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—

(i) For a topping-cycle unit, (A) Useful thermal energy not less than 5 percent of total energy output;
and

(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.

(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;

(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler;
and

(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and thecogeneration system meets on a systemwide basis the requirement in paragraph


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(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such requirement during that calendar year.

Combustion turbine means an enclosed device comprising:

(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from
the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and

(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.

Commence commercial operation means, with regard to a unit:

(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.605.

(i) For a unit that is a TR SO 2 Group 1 unit under § 97.604 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such
date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit that is a TR SO 2 Group 1 unit under § 97.604 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for
commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.605, for a unit that is not a TR

SO 2 Group 1 unit under § 97.604 on the later of November 15, 1990 or the date
the unit commences commercial operation as defined in introductory text of paragraph (1) of this definition, the
unit’s date for commencement of commercial operation shall be the date
on which the unit becomes a TR SO 2 Group 1 unit under § 97.604.

(i) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source),
such date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of
commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

Commence operation means, with regard to a unit:

(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit’s
combustion chamber.

(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source)
after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be
treated as the same unit.

(3) For a unit that is replaced by a unit
at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.

Common stack means a single flue through which emissions from 2 or
more units are exhausted.

Compliance account means an Allowance Management System account, established by the
Administrator for a TR SO 2 Group 1 source under this subpart, in which any

TR SO 2 Group 1 allowance allocations
for the TR SO 2 Group 1 units at the
source are recorded and in which are held any TR SO 2 Group 1 allowances available for use for a control period in complying with the source’s TR SO 2 Group 1 emissions limitation in accordance with § 97.624 and the TR

SO 2 Group 1 assurance provisions in accordance with § 97.625.

Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent
record of SO 2 emissions, stack gas volumetric flow rate, stack gas moisture content, and O 2 or CO 2 concentration (as applicable), in a manner consistent with part 75 of this chapter and §§ 97.630 through 97.635. The following systems are the principal types of continuous emission monitoring systems:

(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A SO 2 monitoring system, consisting of a SO 2 pollutant
concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of SO 2 emissions, in parts per million (ppm);

(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H 2 O;

(4) A CO 2 monitoring system, consisting of a CO 2 pollutant concentration monitor (or an O 2 monitor plus suitable mathematical equations
from which the CO 2 concentration is derived) and an automated data acquisition and handling system and providing a permanent, continuous
record of CO 2 emissions, in percent CO 2 ; and

(5) An O 2 monitoring system, consisting of an O 2 concentration
monitor and an automated data acquisition and handling system and providing a permanent, continuous
record of O 2 , in percent O 2

.

Control period means the period starting January 1 of a calendar year, except as provided in § 97.606(c)(3), and ending on December 31 of the same year, inclusive.

Designated representative means, for

a TR SO 2 Group 1 source and each TR

SO 2 Group 1 unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with this subpart, to represent and legally bind each owner and operator in matters pertaining to the

TR SO 2 Group 1 Trading Program. If the

TR SO 2 Group 1 source is also subject to the Acid Rain Program, TR NO X Annual Trading Program, or TR NO X Ozone Season Trading Program, then this natural person shall be the same natural person as the designated representative, as defined in § 72.2 of this chapter, § 97.402, or § 97.502 respectively.


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Emissions means air pollutants
exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart.

Excess emissions means any ton of

SO 2 emitted from the TR SO 2 Group 1

units at a TR SO 2 Group 1 source during a control period that exceeds the TR SO 2 Group 1 emissions limitation for the

source.

Fossil fuel means— (1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or

(2) For purposes of applying §§ 97.604(b)(2)(i)(B), 97.604(b)(2)(ii)(B), and 97.604(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating
useful heat.

Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 1990 or any calendar year
thereafter.

Fuel oil means any petroleum-based fuel (including diesel fuel or petroleum derivatives such as oil tar) and any recycled or blended petroleum products or petroleum by-products used as a fuel whether in a liquid, solid, or gaseous

state.

General account means an Allowance Management System account, established under this subpart, that is not a compliance account.

Generator means a device that produces electricity.

Gross electrical output means, with regard to a unit, electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Heat input means, with regard to a unit for a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the designated representative and as modified by the
Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.

Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the
fuel.

Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:

(1) For the life of the unit; (2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination;

or (3) For a period no less than 25 years or 70 percent of the economic useful life
of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as of
the initial installation of the unit as specified by the manufacturer of the

unit.

Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.

Nameplate capacity means, starting
from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of such completion as specified by the person conducting the physical change.

Newly affected TR SO 2 Group 1 unit
means a unit that was not a TR SO 2 Group 1 unit when it began operating
but that thereafter becomes a TR SO 2 Group 1 unit.

Operate or operation means, with regard to a unit, to combust fuel. Operator means any person who operates, controls, or supervises a TR

SO 2 Group 1 unit or a TR SO 2 Group 1 source and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit

or source.

Owner means, with regard to a TR SO 2 Group 1 source or a TR SO 2 Group 1 unit at a source respectively, any of the following persons:

(1) Any holder of any portion of the legal or equitable title in a TR SO 2 Group 1 unit at the source or the TR SO 2 Group 1 unit;

(2) Any holder of a leasehold interest

in a TR SO 2 Group 1 unit at the source
or the TR SO 2 Group 1 unit, provided that, unless expressly provided for in a leasehold agreement, ‘‘ owner ’’ shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly)
on the revenues or income from such TR

SO 2 Group 1 unit;

(3) Any purchaser of power from a TR

SO 2 Group 1 unit at the source or the

TR SO 2 Group 1 unit under a life-of-theunit, firm power contractual arrangement;

(4) Provided that, for purposes of applying the TR SO 2 Group 1 assurance provisions in §§ 97.606(c)(2) and 97.625, if one or more owners (as defined in paragraphs (1) through (3) of this definition) of one or more TR SO 2 Group 1 units in a State are wholly owned by another, common owner, all such owners shall be treated collectively as a single owner in the State.

Owner’s assurance level means: (1) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.606(c)(2)(iii)(A) and not as described in § 97.606(c)(2)(iii)(B), the
owner’s share of the State SO 2 Group 1 trading budget with the one-year variability limit for the State for such control period; or

(2) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.606(c)(2)(iii)(B), the owner’s share
of the State SO 2 Group 1 trading budget with the three-year variability limit for the State for such control period.

Owner’s share means: (1) With regard to a total amount of

SO 2 emissions from all TR SO 2 Group 1 units in a State during a control period, the total tonnage of SO 2 emissions during such control period from all of
the owner’s TR SO 2 Group 1 units in the State;

(2) With regard to a State SO 2 Group 1 trading budget with a one-year variability limit for a control period, the


### 45421 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

amount (rounded to the nearest allowance) equal to the total amount of

TR SO 2 Group 1 allowances allocated for such control period to all of the

owner’s TR SO 2 Group 1 units in the State, multiplied by the sum of the State

SO 2 Group 1 trading budget under § 97.610(a) and the State’s one-year variability limit under § 97.610(b) and divided by such State SO 2 Group 1 trading budget;

(3) With regard to a State SO 2 Group 1 trading budget with a three-year variability limit for a control period, the amount (rounded to the nearest allowance) equal to the total amount of

TR SO 2 Group 1 allowances allocated for such control period to all of the

owner’s TR SO 2 Group 1 units in the State, multiplied by the sum of the State

SO 2 Group 1 trading budget under § 97.610(a) and the State’s three-year variability limit under § 97.610(b) and divided by such State SO 2 Group 1 trading budget;

(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of SO 2 emissions and of TR

SO 2 Group 1 allowances allocated for a control period, with regard to such unit, used in determining each owner’s share shall be the amount (rounded to the nearest ton and the nearest allowance) equal to the unit’s SO 2 emissions and allocation of such allowances, respectively, for such control period multiplied by the percentage of ownership in the unit that the owner’s legal, equitable, leasehold, or
contractual reservation or entitlement in the unit comprises as of December 31 of such control period;

(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which

SO 2 mass emissions are reported for a control period for a year, the amount of tonnage of each unit’s SO 2 emissions used in determining each owner’s share for such control period shall be:

(i) The amount (rounded to the nearest ton) of SO 2 emissions reported at the common stack multiplied by the quotient of such unit’s heat input for such control period divided by the total heat input reported from the common stack for such control period;

(ii) An amount determined in accordance with a methodology that the
Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the
Administrator determines will be de minimis; or

(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.635; and (6) Provided that, in the case of a unit that operates during, but is allocated no

TR SO 2 Group 1 allowances for, a control period, the unit shall be treated, solely for purposes of this definition, as being allocated an amount (rounded to the nearest allowance) of TR SO 2 Group 1 allowances for such control period equal to the lesser of—

(i) The unit’s allowable SO 2 emission rate (in lb per MWe) applicable to such control period, multiplied by a capacity factor of 0.84 (if the unit is a coal-fired boiler), 0.15 (if the unit is a simple combustion turbine), or 0.66 (if the unit is a combined cycle turbine), multiplied by the unit’s maximum hourly load as reported in accordance with this subpart and by 8,760 hours/control period, and divided by 2,000 lb/ton; or

(ii) For a unit listed in appendix A to this subpart, the sum of the unit’s SO 2 emissions in the control period in the last three years during which the unit operated during the control period, divided by three.

Permanently retired means, with regard to a unit, a unit that is
unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.

Permitting authority means

‘‘ permitting authority ’’ as defined in §§ 70.2 and 71.2 of this chapter.

Potential electrical output capacity means 33 percent of a unit’s maximum design heat input, divided by 3,413 Btu/ kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.

Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of
business.

Recordation, record, or recorded means, with regard to TR SO 2 Group 1 allowances, the moving of TR SO 2 Group 1 allowances by the Administrator into, out of, or between Allowance Management System accounts, for purposes of allocation, transfer, or deduction.

Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.

Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).

Sequential use of energy means: (1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application

or process; or

(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.

Serial number means, for a TR SO 2 Group 1 allowance, the unique identification number assigned to each

TR SO 2 Group 1 allowance by the
Administrator.

Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion
turbine that is a ‘‘ solid waste

incineration unit ’’ as defined in section 129(g)(1) of the Clean Air Act.

Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the
definition of ‘‘ major source ’’

, ‘‘ stationary

source ’’ , or ‘‘ source ’’ as set forth and implemented in a title V operating permit program or any other program
under the Clean Air Act.

State means one of the States or the District of Columbia that is subject to
the TR SO 2 Group 1 Trading Program pursuant to § 52.38(b) of this chapter.

Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(1) In person; (2) By United States Postal Service; or (3) By other means of dispatch or transmission and delivery;

(4) Provided that compliance with any

‘‘ submission ’’ or ‘‘ service ’’ deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.

Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.

Total energy input means total energy of all forms supplied to a unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as
follows:

LHV = HHV ¥ 10.55(W + 9H)

Where: LHV = lower heating value of the form of energy in Btu/lb,


### 45422 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

HHV = higher heating value of the form of energy in Btu/lb, W = weight % of moisture in the form of energy, and H = weight % of hydrogen in the form of

energy. Total energy output means the sum of useful power and useful thermal energy produced by the unit.

TR NO X Annual Trading Program
means a multi-state NO X air pollution control and emission reduction program established by the Administrator in accordance with subpart AAAAA and 52.37(a) of this chapter, as a means of mitigating interstate transport of fine particulates and NO X.

TR NO X Ozone Season Trading Program means a multi-state NO X air pollution control and emission reduction program established by the
Administrator in accordance with subpart BBBBB of this part and 52.37(b) of this chapter, as a means of mitigating interstate transport of ozone and NO X.

TR SO 2 Group 1 allowance means a limited authorization issued and allocated by the Administrator under this subpart to emit one ton of SO 2 during a control period of the specified calendar year for which the authorization is allocated or of any calendar year thereafter under the TR

SO 2 Group 1 Trading Program.

TR SO 2 Group 1 allowance deduction
or deduct TR SO 2 Group 1 allowances means the permanent withdrawal of TR

SO 2 Group 1 allowances by the Administrator from a compliance

account, e.g., in order to account for compliance with the TR SO 2 Group 1
emissions limitation or assurance provisions.

TR SO 2 Group 1 allowances held or
hold TR SO 2 Group 1 allowances means the TR SO 2 Group 1 allowances treated
as included in an Allowance Management System account as of a specified point in time because at that time they:

(1) Have been recorded by the
Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR SO 2 Group 1 allowance transfer in accordance with this subpart;
and

(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR SO 2 Group 1
allowance transfer in accordance with this subpart.

TR SO 2 Group 1 emissions limitation means, for a TR SO 2 Group 1 source, the tonnage of SO 2 emissions authorized in a control period by the TR SO 2 Group
1 allowances available for deduction for the source under § 97.624(a) for such control period. TR SO 2 Group 1 source means a source that includes one or more TR

SO 2 Group 1 units.

TR SO 2 Group 1 Trading Program
means a multi-state SO 2 air pollution control and emission reduction program established by the Administrator in accordance with this subpart and 52.38(b) of this chapter, as a means of mitigating interstate transport of fine particulates and SO 2.

TR SO 2 Group 1 unit means a unit that is subject to the TR SO 2 Group 1 Trading Program under § 97.604.

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary,
fossil-fuel-fired combustion device.

Unit operating day means a calendar day in which a unit combusts any fuel.

Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.

Useful power means electricity or mechanical energy that a unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means thermal energy that is:

(1) Made available to an industrial or commercial process (not a power production process), excluding any heat
contained in condensate return or makeup water;

(2) Used in a heating application (e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application (i.e., in an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to

customers.

**§ 97.603 Measurements, abbreviations, and acronyms.** 

Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:

Btu—British thermal unit

CO 2 —carbon dioxide

H 2 O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour lb—pound
mmBtu—million Btu MWe—megawatt electrical MWh—megawatt hour

NO X —nitrogen oxides

O 2 —oxygen ppm—parts per million scfh—standard cubic feet per hour

SO 2 —sulfur dioxide yr—year

**§ 97.604 Applicability.**

(a) Except as provided in paragraph (b) of this section:

(1) The following units in a State shall
be TR SO 2 Group 1 units, and any
source that includes one or more such
units shall be a TR SO 2 Group 1 source, subject to the requirements of this subpart: 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 chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a

TR SO 2 Group 1 unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the
unit shall become a TR SO 2 Group 1 unit as provided in paragraph (a)(1) of
this section on the first date on which
it both combusts fossil fuel and serves such generator.

(b) Any unit in a State that otherwise

is a TR SO 2 Group 1 unit under paragraph (a) of this section and that meets the requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR SO 2 Group 1 unit:

(1)(i) Any unit: (A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and

(B) Not serving at any time, since thelater of November 15, 1990 or the startup of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system
for sale.

(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12- month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the
unit shall become a TR SO 2 Group 1 unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of paragraph (b)(1)(i)(B) of this section.


### 45423 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

(2)(i) Any unit commencing operation before January 1, 1985:

(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average annual fuel consumption of fossil fuel for 1985– 1987 less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(ii) Any unit commencing operation on or after January 1, 1985:

(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average annual fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a

TR SO 2 Group 1 unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a solid waste incineration unit or January 1 after the first 3 consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of fossil fuel of 20 percent or more.

(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR SO 2 Group 1 Trading Program to the unit or other equipment.

(1) Petition content. The petition shall be in writing and include the
identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying
official: ‘‘ I am authorized to make this
submission on behalf of the owners and operators of the unit or other equipment
for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR SO 2 Group 1 Trading Program to the unit or other equipment shall be binding on any permitting authority unless the
Administrator determines that the petition or other documents or information provided in connection with the petition contained significant,
relevant errors or omissions.

**§ 97.605 Retired unit exemption.**

(a)(1) Any TR SO 2 Group 1 unit that is permanently retired and is not a TR

SO 2 Group 1 opt-in unit shall be exempt from § 97.606(b) and (c)(1), § 97.624, and §§ 97.630 through 97.635.

(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR SO 2 Group 1 unit is permanently retired. Within 30 days of the unit’s permanent retirement, the designated representative shall submit a statement
to the Administrator. The statement shall state, in a format prescribed by the Administrator, that the unit was permanently retired on a specified date and will comply with the requirements of paragraph (b) of this section.

(b) Special provisions. (1) A unit exempt under paragraph (a) of this section shall not emit any SO 2 , starting on the date that the exemption takes
effect.

(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR

SO 2 Group 1 Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect.

(4) A unit exempt under paragraph (a) of this section shall lose its exemption
on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.

**§ 97.606 Standard requirements.**

(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.613 through 97.618.

(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each TR

SO 2 Group 1 source and each TR SO 2 Group 1 unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of §§ 97.630 through 97.635.

(2) The emissions data determined in accordance with §§ 97.630 through
97.635 shall be used to calculate
allocations of TR SO 2 Group 1 allowances under §§ 97.611(a)(2) and (b)
and 97.612 and to determine compliance with the TR SO 2 Group 1
emissions limitation and assurance provisions under paragraph (c) of this section, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location
determined in accordance with §§ 97.630 through 97.635 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be

zero.

(c) SO 2 emissions requirements —(1)

TR SO 2 Group 1 emissions limitation. (i)
As of the allowance transfer deadline for


### 45424 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

a control period, the owners and operators of each TR SO 2 Group 1
source and each TR SO 2 Group 1 unit at the source shall hold, in the source’s compliance account, TR SO 2 Group 1
allowances available for deduction for such control period under § 97.624(a) in
an amount not less than the tons of total

SO 2 emissions for such control period
from all TR SO 2 Group 1 units at the

source.

(ii) If a TR SO 2 Group 1 source emits

SO 2 during any control period in excess
of the TR SO 2 Group 1 emissions limitation set forth in paragraph (c)(1)(i) of this section, then:

(A) The owners and operators of the
source and each TR SO 2 Group 1 unit
at the source shall hold the TR SO 2 Group 1 allowances required for deduction under § 97.624(d) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act; and

(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.

(2) TR SO 2 Group 1 assurance provisions. (i) If the total amount of SO 2 emissions from all TR SO 2 Group 1 units in a State during a control period in 2014 or any year thereafter exceeds
the State assurance level as described in paragraph (c)(2)(iii) of this section, then
each owner whose share of such SO 2 emissions during such control period
exceeds the owner’s assurance level for the State and such control period shall hold, in a compliance account designated by the owner in accordance with § 97.625(b)(4)(ii), TR SO 2 Group 1
allowances available for deduction for such control period under § 97.625(a) in an amount equal to the product, as determined by the Administrator in accordance with § 97.625(b), of multiplying—

(A) The quotient (rounded to the nearest whole number) of the amount by
which the owner’s share of such SO 2 emissions exceeds the owner’s assurance level divided by the sum of the amounts, determined for all such owners, by which each owner’s share of
such SO 2 emissions exceeds that owner’s assurance level; and

(B) The amount by which total SO 2 emissions for all TR SO 2 Group 1 units in the State for such control period
exceed the State assurance level as
determined in accordance with paragraph (c)(2)(iii) of this section.

(ii) The owner shall hold the TR SO 2 Group 1 allowances required under paragraph (c)(2)(i) of this section, as of midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such control period.

(iii) The total amount of SO 2 emissions from all TR SO 2 Group 1 units in a State during a control period in 2014 or any year thereafter exceeds
the State assurance level:

(A) If such total amount of SO 2 emissions exceeds the sum, for such control period, of the State SO 2 Group1 trading budget and the State’s oneyear variability limit under § 97.610(b);

or (B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount
of SO 2 emissions and the total amounts
of SO 2 emissions from all TR SO 2 Group 1 units in the State during the control periods in the immediately preceding two years exceeds the sum, for such control period, of the State SO 2 Group1 trading budget and the State’s threeyear variability limit under § 97.610(b);

(C) Provided that the amount by
which such total amount of SO 2 emissions exceeds the State assurance level shall be the greater of the amounts
of the exceedance calculated under paragraph (c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of this

section.

(iv) It shall not be a violation of this subpart or of the Clean Air Act if the
total amount of SO 2 emissions from all

TR SO 2 Group 1 units in a State during a control period exceeds the State
assurance level or if an owner’s share of
total SO 2 emissions from the TR SO 2 Group 1 units in a State during a control period exceeds the owner’s assurance
level.

(v) To the extent an owner fails to
hold TR SO 2 Group 1 allowances for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section,

(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and

(B) Each TR SO 2 Group 1 allowance
that the owner fails to hold for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.

(3) Compliance periods. A TR SO 2 Group 1 unit shall be subject to the requirements:

(i) Under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2012 or the deadline for meeting the unit’s monitor certification requirements under § 97.630(b) and for each control period thereafter; and (ii) Under paragraph (c)(2) of this section for the control period starting on the later of January 1, 2014 or the deadline for meeting the unit’s monitor certification requirements under § 97.630(b) and for each control period
thereafter.

(4) Vintage of deducted allowances. A
TR SO 2 Group 1 allowance shall not be deducted, for compliance with the requirements under paragraphs (c)(1) and (2) of this section, for a control period in a calendar year before the year
for which the TR SO 2 Group 1
allowance was allocated.

(5) Allowance Management System requirements. Each TR SO 2 Group 1 allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with this subpart.

(6) Limited authorization. (i) A TR

SO 2 Group 1 allowance is a limited
authorization to emit one ton of SO 2 in
accordance with the TR SO 2 Group 1 Trading Program.

(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to
terminate or limit such authorization to
the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean

Air Act.

(7) Property right. A TR SO 2 Group 1 allowance does not constitute a property right.

(d) Title V Permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction,
or transfer of TR SO 2 Group 1
allowances in accordance with this subpart.

(2) A description of whether a unit is required to monitor and report SO 2 emissions using a continuous emission monitoring system (under §§ 75.10, 75.11, and 75.16 of this chapter), an excepted monitoring system (under appendix D to part 75 of this chapter), a low mass emissions excepted monitoring methodology (under § 75.19 of this chapter), or an alternative monitoring system (under subpart E of part 75 of this chapter) in accordance with §§ 97.630 through 97.635 may be added to, or changed in, a title V permit using minor permit modification procedures in accordance with §§ 70.7(e)(2) and 71.7(e)(1) of this chapter, provided that the requirements applicable to the described monitoring and reporting (as added or changed, respectively) are already incorporated in such permit. This paragraph explicitly provides that the addition of, or change to, a unit’s description as described in the prior sentence is eligible for minor


### 45425 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

permit modification procedures in accordance with §§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.

(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each TR SO 2 Group 1
source and each TR SO 2 Group 1 unit at the source shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by
the Administrator.

(i) The certificate of representation under § 97.616 for the designated representative for the source and each

TR SO 2 Group 1 unit at the source and
all documents that demonstrate the
truth of the statements in the certificate of representation; provided that the
certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of
the submission of a new certificate of representation under § 97.616 changing the designated representative.

(ii) All emissions monitoring information, in accordance with this subpart.

(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR SO 2 Group 1 Trading Program, including any monitoring plans and monitoring system certification and recertification applications.

(2) The designated representative of a

TR SO 2 Group 1 source and each TR

SO 2 Group 1 unit at the source shall make all submissions required under
the TR SO 2 Group 1 Trading Program, including any submissions required for compliance with the TR SO 2 Group 1 assurance provisions. This requirement does not change, create an exemption from, or otherwise affect the responsible official submission requirements under a title V operating permit program in parts 70 and 71 of this chapter.

(f) Liability. (1) Any provision of the

TR SO 2 Group 1 Trading Program that applies to a TR SO 2 Group 1 source or the designated representative of a TR

SO 2 Group 1 source shall also apply to the owners and operators of such source
and of the TR SO 2 Group 1 units at the

source.

(2) Any provision of the TR SO 2 Group 1 Trading Program that applies to

a TR SO 2 Group 1 unit or the designated representative of a TR SO 2 Group 1 unit shall also apply to the owners and operators of such unit.

(g) Effect on other authorities. No provision of the TR SO 2 Group 1 Trading Program or exemption under § 97.605 shall be construed as exempting or excluding the owners and operators, and the designated representative, of a TR SO 2 Group 1

source or TR SO 2 Group 1 unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

**§ 97.607 Computation of time.**

(a) Unless otherwise stated, any time period scheduled, under the TR SO 2 Group 1 Trading Program, to begin on
the occurrence of an act or event shall begin on the day the act or event occurs.

(b) Unless otherwise stated, any time period scheduled, under the TR SO 2 Group 1 Trading Program, to begin
before the occurrence of an act or event shall be computed so that the period ends the day before the act or event

occurs.

(c) Unless otherwise stated, if the final day of any time period, under the TR

SO 2 Group 1 Trading Program, falls on a weekend or a State or Federal holiday, the time period shall be extended to the next business day.

**§ 97.608 Administrative appeal procedures.** 

The administrative appeal procedures
for decisions of the Administrator under
the TR SO 2 Group 1 Trading Program are set forth in part 78 of this chapter.

**§ 97.609 [Reserved]**

**§ 97.610 State SO** 2 **Group 1 trading budgets, new-unit set-asides, and variability** 
**limits.**

(a) The State SO 2 Group 1 trading budgets and new-unit set-asides for
allocations of TR SO 2 Group 1 allowances for the control periods in
2012 and thereafter are as follows:

State SO 2 Group 1 trading budget (tons) * New-unit set-aside (tons)

For 2012–2013 For 2014 and thereafter For 2012–2013 For 2014 and thereafter

Georgia .................................................................................................... 233,260 85,717 6,998 2,572 Illinois ....................................................................................................... 208,957 151,530 6,269 4,546 Indiana ..................................................................................................... 400,378 201,412 12, 011 6,042
Iowa ......................................................................................................... 94,052 86,088 2,82 2 2,583 Kentucky .................................................................................................. 219,549 113,844 6,586 3,415 Michigan ................................................................................................... 251,337 155,675 7,54 0 4,670 Missouri .................................................................................................... 203,689 158,764 6,1 11 4,763
New York ................................................................................................. 66,542 42,041 1,996 1, 261 North Carolina .......................................................................................... 111,485 81,859 3,345 2, 456 Ohio ......................................................................................................... 464,964 178,307 13 ,949 5,349 Pennsylvania ............................................................................................ 388,612 141,693 11,658 4,251 Tennessee ............................................................................................... 100,007 100,007 3,000 3 ,000 Virginia ..................................................................................................... 72,595 40,785 2,17 8 1,224 West Virginia ............................................................................................ 205,422 119,016 6,163 3,570
Wisconsin ................................................................................................. 96,439 66,683 2,893 2 ,000

Total .................................................................................................. 3,117,288 1,723,421 93,5 19 51,703

* Without variability limits.

(b) The States’ one-year and three-year variability limits for the State SO 2 Group 1 trading budgets for the control periods in 2014 and thereafter are as

follows:


### 45426 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

State One-year variability limits Three-year variability limits

2014 and thereafter

(tons) 2016 and thereafter

(tons)

Georgia ........................................................................................................................ ........................ 8,572 4,949
Illinois ....................................................................................................................... ............................ 15,153 8,749
Indiana ........................................................................................................................ ......................... 20,141 11,629
Iowa ........................................................................................................................... .......................... 8,609 4,970 Kentucky ....................................................................................................................... ....................... 11,384 6,573 Michigan ....................................................................................................................... ........................ 15,568 8,988
Missouri ....................................................................................................................... ......................... 15,876 9,166
New York ....................................................................................................................... ...................... 4,204 2,427
North Carolina ................................................................................................................. ..................... 8,186 4,726
Ohio ........................................................................................................................... .......................... 17,831 10,295 Pennsylvania ................................................................................................................... ..................... 14,169 8,181
Tennessee ...................................................................................................................... ..................... 10,001 5,774 Virginia ....................................................................................................................... .......................... 4,079 2,355 West Virginia .................................................................................................................. ...................... 11,902 6,871
Wisconsin ...................................................................................................................... ....................... 6,668 3,850

**§ 97.611 Timing requirements for TR SO** 2 **Group 1 allowance allocations.**

(a) Existing units. (1) TR SO 2 Group 1 allowances are allocated, for the control periods in 2012 and each year thereafter, as set forth in appendix A to this subpart. Listing a unit in such appendix does not constitute a
determination that the unit is a TR SO 2 Group 1 unit, and not listing a unit in such appendix does not constitute a
determination that the unit is not a TR

SO 2 Group 1 unit.

(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being
allocated TR SO 2 Group 1 allowances does not operate, starting after 2011, during the control period in three consecutive years, such unit will not be
allocated the TR SO 2 Group 1 allowances set forth in appendix A to this subpart for the unit for the control periods in the seventh year after the first such year and in each year after that seventh year. All TR SO 2 Group 1
allowances that would otherwise have
been allocated to such unit will be
allocated to the new unit set-aside for the respective years involved. If such unit resumes operation, the
Administrator will allocate TR SO 2 Group 1 allowances to the unit in accordance with paragraph (b) of this

section.

(b) New units. (1) By July 1, 2012 and July 1 of each year thereafter, the
Administrator will calculate the TR SO 2 Group 1 allowance allocation for each

TR SO 2 Group 1 unit, in accordance with § 97.612, for the control period in the year of the applicable calculation deadline under this paragraph and will promulgate a notice of availability of the
results of the calculations.

(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced
in such notice.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations are in accordance with § 97.612 and §§ 97.606(b)(2) and 97.630 through

97.635.

(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By September 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(c) Units that are not TR SO 2 Group

1 units. For each control period in 2012 and thereafter, if the Administrator
determines that TR SO 2 Group 1
allowances were allocated under paragraph (a) of this section for the control period to a recipient that is not actually a TR SO 2 Group 1 unit under § 97.604 as of January 1, 2012 or whose deadline for meeting monitor certification requirements under § 97.630(b)(1) and (2) is after January 1,
2012 or if the Administrator determines
that TR SO 2 Group 1 allowances were allocated under paragraph (b) of this section and § 97.612 for the control period to a recipient that is not actually

a TR SO 2 Group 1 unit under § 97.604 as of January 1 of the control period, then the Administrator will notify the designated representative and will act in accordance with the following procedures: (1) Except as provided in paragraph (c)(2) or (3) of this section, the
Administrator will not record such TR

SO 2 Group 1 allowances under § 97.621.

(2) If the Administrator already
recorded such TR SO 2 Group 1 allowances under § 97.621 and if the
Administrator makes such determination before making deductions
for the source that includes such recipient under § 97.624(b) for such control period, then the Administrator
will deduct from the account in which
such TR SO 2 Group 1 allowances were
recorded an amount of TR SO 2 Group 1
allowances allocated for the same or a prior control period equal to the amount of such already recorded TR SO 2 Group
1 allowances. The authorized account representative shall ensure that there are
sufficient TR SO 2 Group 1 allowances in such account for completion of the
deduction.

(3) If the Administrator already
recorded such TR SO 2 Group 1 allowances under § 97.621 and if the
Administrator makes such determination after making deductions
for the source that includes such recipient under § 97.624(b) for such control period, then the Administrator will not make any deduction to take account of such already recorded TR

SO 2 Group 1 allowances.

(4) The Administrator will transfer the

TR SO 2 Group 1 allowances that are not recorded, or that are deducted, in accordance with paragraphs (c)(1) and(2) of this section to the new unit setaside, for the State in which such recipient is located, for the control period in the year of such transfer if the notice required in paragraph (b)(1) of this section for the control period in that year has not been promulgated or, if such notice has been promulgated, in the next year.


### 45427 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

**§ 97.612 TR SO** 2 **Group 1 allowance**
**allocations for new units.**

(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR SO 2 Group 1
allowances to TR SO 2 Group 1 units in a State that are not listed in appendix A to this subpart, to TR SO 2 Group 1
units that are so listed and whose
allocation of SO 2 Group 1 allowances for such control period is covered by § 97.611(c)(1) or (2), and to TR SO 2 Group 1 units that are so listed and, pursuant to § 97.611(a)(2), are not
allocated TR SO 2 Group 1 allowances for such control period but that operate during the immediately preceding control period:

(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be
allocated TR SO 2 Group 1 allowances in an amount equal to the applicable
amount of tons of SO 2 emissions as setforth in § 97.610(a). Each new unit setaside will be allocated additional TR

SO 2 Group 1 allowances in accordance with § 97.611(a)(2) and (c)(4).

(2) The designated representative of
such TR SO 2 Group 1 unit may submit to the Administrator a request, in a format prescribed by the Administrator,
to be allocated TR SO 2 Group 1 allowances for a control period, starting with the later of the control period in 2012, the first control period after the control period in which the TR SO 2 Group 1 unit commences commercial operation (for a unit not listed in appendix A to this subpart), or the first control period after the control period in which the unit resumes operation (for a unit listed in appendix A of this subpart) and for each subsequent control period.

(i) The request must be submitted on or before May 1 of the first control period for which TR SO 2 Group 1 allowances are sought and after the date
on which the TR SO 2 Group 1 unit commences commercial operation (for a unit not listed in appendix A of this subpart) or on which the unit resumes operation (for a unit listed in appendix A of this subpart).

(ii) For each control period for which an allocation is sought, the request must
be for TR SO 2 Group 1 allowances in an amount equal to the unit’s total tons of

SO 2 emissions during the immediately preceding control period.

(3) The Administrator will review
each TR SO 2 Group 1 allowance allocation request under paragraph (a)(2) of this section and will accept the request only if it meets the requirements of paragraph (a)(2) of this section. The Administrator will allocate TR SO 2 Group 1 allowances for each control period pursuant to an accepted request
as follows:

(i) After May 1 of such control period,
the Administrator will determine the
sum of the TR SO 2 Group 1 allowances requested in all accepted allowance allocation requests for such control period.

(ii) If the amount of TR SO 2 Group 1
allowances in the new unit set-aside for such control period is greater than or equal to the sum under paragraph (a)(3)(i) of this section, then the
Administrator will allocate the amount
of TR SO 2 Group 1 allowances requested
to each TR SO 2 Group 1 unit covered by an accepted allowance allocation request.

(iii) If the amount of TR SO 2 Group 1
allowances in the new unit set-aside for such control period is less than the sum under paragraph (a)(3)(i) of this section,
then the Administrator will allocate to
each TR SO 2 Group 1 unit covered by an accepted allowance allocation request the amount of the TR SO 2 Group 1 allowances requested, multiplied by
the amount of TR SO 2 Group 1
allowances in the new unit set-aside for such control period, divided by the sum determined under paragraph (a)(3)(i) of this section, and rounded to the nearest
allowance.

(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.611(b), each designated representative that submitted an allowance allocation request of the
amount of TR SO 2 Group 1 allowances (if any) allocated for such control period
to the TR SO 2 Group 1 unit covered by the request.

(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any
unallocated TR SO 2 Group 1 allowances
remain in the new unit set-aside under paragraph (a) of this section for a State for such control period, the
Administrator will allocate to each TR

SO 2 Group 1 unit that is in the State, is listed in appendix A to this subpart, and
continues to be allocated TR SO 2 Group 1 allowances for such control period in accordance with § 97.611(a)(2), an
amount of TR SO 2 Group 1 allowances equal to the following: The total amount of such remaining unallocated TR SO 2 Group 1 allowances in such new unit set-aside, multiplied by the unit’s allocation under § 97.611(a) for such control period, divided by the
remainder of the amount of tons in the applicable State SO 2 Group 1 trading budget minus the amount of tons in such new unit set-aside, and rounded to
the nearest allowance.

**§ 97.613 Authorization of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.615,
each TR SO 2 Group 1 source, including
all TR SO 2 Group 1 units at the source, shall have one and only one designated representative, with regard to all matters
under the TR SO 2 Group 1 Trading Program.

(1) The designated representative shall be selected by an agreement binding on the owners and operators of
the source and all TR SO 2 Group 1 units
at the source and shall act in accordance
with the certification statement in § 97.616(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.616:

(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source
and each TR SO 2 Group 1 unit at the source in all matters pertaining to the

TR SO 2 Group 1 Trading Program, notwithstanding any agreement between the designated representative and such owners and operators; and

(ii) The owners and operators of the
source and each TR SO 2 Group 1 unit at the source shall be bound by any
decision or order issued to the designated representative by the Administrator regarding the source or any such unit.

(b) Except as provided under § 97.615,
each TR SO 2 Group 1 source may have one and only one alternate designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.

(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR SO 2 Group 1 units at the source and shall act
in accordance with the certification statement in § 97.616(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.616,

(i) The alternate designated representative shall be authorized;

(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action,


### 45428 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

inaction, or submission by the designated representative; and

(iii) The owners and operators of the
source and each TR SO 2 Group 1 unit at the source shall be bound by any
decision or order issued to the alternate designated representative by the Administrator regarding the source or any such unit. (c) Except in this section, § 97.602, and §§ 97.614 through 97.618,
whenever the term ‘‘ designated representative ’’ is used in this subpart,
the term shall be construed to include the designated representative or any alternate designated representative.

**§ 97.614 Responsibilities of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.618 concerning delegation of authority to make submissions, each submission
under the TR SO 2 Group 1 Trading Program shall be made, signed, and certified by the designated representative or alternate designated representative for each TR SO 2 Group 1
source and TR SO 2 Group 1 unit for
which the submission is made. Each
such submission shall include the following certification statement by the designated representative or alternate designated representative: ‘‘ I am authorized to make this submission on behalf of the owners and operators of
the source or units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the
statements and information submitted
in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(b) The Administrator will accept or
act on a submission made for a TR SO 2 Group 1 source or a TR SO 2 Group 1 unit only if the submission has been made, signed, and certified in accordance with paragraph (a) of this section and § 97.618.

**§ 97.615 Changing designated representative and alternate designated**  **representative; changes in owners and operators.** 

(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.616. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date
when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the TR SO 2 Group 1 source
and the TR SO 2 Group 1 units at the

source.

(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.616. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the
time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the TR SO 2 Group 1 source and the TR SO 2 Group
1 units at the source.

(c) Changes in owners and operators. (1) In the event an owner or operator of

a TR SO 2 Group 1 source or a TR SO 2 Group 1 unit is not included in the list of owners and operators in the certificate of representation under § 97.616, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the source or unit, and the decisions and orders of the Administrator, as if the owner or operator were included in such list.

(2) Within 30 days after any change in the owners and operators of a TR SO 2 Group 1 source or a TR SO 2 Group 1 unit, including the addition of a new owner or operator, the designated representative or any alternate designated representative shall submit a
revision to the certificate of representation under § 97.616 amending the list of owners and operators to include the change.

**§ 97.616 Certificate of representation.**

(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:

(1) Identification of the TR SO 2 Group 1 source, and each TR SO 2 Group 1 unit at the source, for which the certificate of representation is submitted, including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type, identification number and nameplate capacity (in MWe rounded to the nearest tenth) of each generator served by each such unit, and actual or projected date of commencement of commercial operation.

(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

(3) A list of the owners and operators
of the TR SO 2 Group 1 source and of
each TR SO 2 Group 1 unit at the source.

(4) The following certification statements by the designated representative and any alternate designated representative—

(i) ‘‘ I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR

SO 2 Group 1 unit at the source. ’’

(ii) ‘‘ I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR

SO 2 Group 1 Trading Program on behalf of the owners and operators of the
source and of each TR SO 2 Group 1 unit
at the source and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions and by any order issued to me by the Administrator regarding the

source or unit. ’’

(iii) ‘‘ Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR SO 2 Group 1 unit, or where a utility or industrial customer purchases power from a TR

SO 2 Group 1 unit under a life-of-theunit, firm power contractual arrangement, I certify that: I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of each TR

SO 2 Group 1 unit at the source; and TR

SO 2 Group 1 allowances and proceeds of transactions involving TR SO 2 Group
1 allowances will be deemed to be held or distributed in proportion to each holder’s legal, equitable, leasehold, or contractual reservation or entitlement, except that, if such multiple holders have expressly provided for a different
distribution of TR SO 2 Group 1 allowances by contract, TR SO 2 Group 1 allowances and proceeds of transactions involving TR SO 2 Group 1
allowances will be deemed to be held or


### 45429 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

distributed in accordance with the

contract. ’’

(5) The signature of the designated representative and any alternate designated representative and the dates signed.

(b) Unless otherwise required by the Administrator, documents of agreement
referred to in the certificate of representation shall not be submitted to
the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

**§ 97.617 Objections concerning designated representative and alternate**  **designated representative.**

(a) Once a complete certificate of representation under § 97.616 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.616 is received by the Administrator.

(b) Except as provided in § 97.615(a) or (b), no objection or other
communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator
under the TR SO 2 Group 1 Trading Program.

(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR

SO 2 Group 1 allowance transfers.

**§ 97.618 Delegation by designated representative and alternate designated**  **representative.**

(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(c) In order to delegate authority to
make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;

(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an

‘‘ agent ’’ );

(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and

(4) The following certification statements by such designated representative or alternate designated representative:

(i) ‘‘ I agree that any electronic
submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.618(d) shall be deemed to be an electronic submission by me. ’’

(ii) ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.618(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me
under 40 CFR 97.618 is terminated. ’’

.

(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(e) Any electronic submission covered by the certification in paragraph (c)(4)(i)
of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall
be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.

**§ 97.619 [Reserved]**

**§ 97.620 Establishment of Allowance Management System accounts.** 

(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.616, the
Administrator will establish a compliance account for the TR SO 2 Group 1 source for which the certificate of representation was submitted, unless the source already has a compliance account. The designated representative and any alternate designated representative of the source shall be the authorized account representative and
the alternate authorized account representative respectively of the compliance account.

(b) General accounts —(1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring TR

SO 2 Group 1 allowances, by submitting to the Administrator a complete application for a general account. Such application shall designate one and only one authorized account representative and may designate one and only one
alternate authorized account representative who may act on behalf of the authorized account representative.

(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR SO 2 Group 1 allowances held in the general account.

(B) The agreement by which the
alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act
in lieu of the authorized account representative.

(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:

(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;

(B) An identifying name for the general account;

(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to


### 45430 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

represent their ownership interest with respect to the TR SO 2 Group 1 allowances held in the general account;

(D) The following certification statement by the authorized account representative and any alternate authorized account representative: ‘‘ I certify that I was selected as the authorized account representative or the
alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR SO 2 Group 1 allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities
under the TR SO 2 Group 1 Trading Program on behalf of such persons and that each such person shall be fully bound by my representations, actions, inactions, or submissions and by any order or decision issued to me by the Administrator regarding the general

account. ’’

(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.

(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted
to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted and upon and after such receipt by the Administrator:

(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to TR

SO 2 Group 1 allowances held in the general account in all matters pertaining
to the TR SO 2 Group 1 Trading Program, notwithstanding any agreement between the authorized account representative and such person.

(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative. (C) Each person who has an ownership interest with respect to TR

SO 2 Group 1 allowances held in the general account shall be bound by any
order or decision issued to the authorized account representative or
alternate authorized account representative by the Administrator regarding the general account. (ii) Except as provided in paragraph (b)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to TR SO 2 Group 1 allowances held in the general
account. Each such submission shall include the following certification statement by the authorized account representative or any alternate authorized account representative: ‘‘ I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the

TR SO 2 Group 1 allowances held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements
and information submitted in this
document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(iii) Except in this section, whenever
the term ‘‘ authorized account representative ’’ is used in this subpart,
the term shall be construed to include the authorized account representative or any alternate authorized account representative.

(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the TR SO 2 Group 1 allowances in the general account.

(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new
alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the

TR SO 2 Group 1 allowances in the general account.

(iii)(A) In the event a person having an ownership interest with respect to

TR SO 2 Group 1 allowances in the general account is not included in the list of such persons in the application for a general account, such person shall be deemed to be subject to and bound by the application for a general account, the representation, actions, inactions,
and submissions of the authorized account representative and any alternate authorized account representative of the account, and the decisions and orders of the Administrator, as if the person were
included in such list.

(B) Within 30 days after any change in the persons having an ownership interest with respect to SO 2 Group 1 allowances in the general account, including the addition of a new person, the authorized account representative or any alternate authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the

TR SO 2 Group 1 allowances in the general account to include the change.

(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (b)(1)
of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the
Administrator.

(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication
submitted to the Administrator concerning the authorization, or any


### 45431 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the
Administrator under the TR SO 2 Group 1 Trading Program.

(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR

SO 2 Group 1 allowance transfers.

(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(iii) In order to delegate authority to
make an electronic submission to the
Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or
alternate authorized account representative, as appropriate, must
submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any)
of such authorized account representative or alternate authorized account representative;

(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to

as an ‘‘ agent ’’ );

(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;

(D) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ I agree that any
electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is
made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.620(b)(5)(iv) shall be deemed to be an electronic submission by me. ’’ ; and

(E) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.620(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.620(b)(5) is terminated. ’’

.

(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or
alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or
alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of
this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.

(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR SO 2 Group 1 allowance transfer under § 97.622 for any TR SO 2 Group 1 allowances in the
account to one or more other Allowance Management System accounts.

(ii) If a general account has no TR SO 2 Group 1 allowance transfers to or from the account for a 12-month period or longer and does not contain any TR SO 2 Group 1 allowances, the Administrator may notify the authorized account representative for the account that the
account will be closed after 20 business days after the notice is sent. The account will be closed after the 20-day period unless, before the end of the 20- day period, the Administrator receives a correctly submitted TR SO 2 Group 1 allowance transfer under § 97.622 to the account or a statement submitted by the authorized account representative or
alternate authorized account representative demonstrating to the satisfaction of the Administrator good cause as to why the account should not
be closed.

(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of
this section.

(d) Responsibilities of authorized account representative and alternate authorized account representative. After
the establishment of an Allowance Management System account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction
or transfer of TR SO 2 Group 1 allowances in the account, only if the submission has been made, signed, and certified in accordance with §§ 97.614(a) and 97.618 or paragraphs (b)(2)(ii) and (b)(5) of this section.

**§ 97.621 Recordation of TR SO** 2 **Group 1**

**allowance allocations.**

(a) By September 1, 2011, the
Administrator will record in each TR

SO 2 Group 1 source’s compliance
account the TR SO 2 Group 1 allowances
allocated for the TR SO 2 Group 1 units
at the source in accordance with §§ 97.611(a) for the control periods in 2012, 2013, and 2014.

(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will
record in each TR SO 2 Group 1 source’s compliance account the TR SO 2 Group
1 allowances allocated for the TR SO 2 Group 1 units at the source in accordance with § 97.611(a) for the control period in the third year after the year of the applicable recordation deadline under this paragraph.

(c) By September 1, 2012 and September 1 of each year thereafter, the
Administrator will record in each TR

SO 2 Group 1 source’s compliance
account the TR SO 2 Group 1 allowances
allocated for the TR SO 2 Group 1 units
at the source in accordance with § 97.612 for the control period in the year of the applicable recordation deadline under this paragraph.

(d) When recording the allocation of

TR SO 2 Group 1 allowances for a TR


### 45432 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

SO 2 Group 1 unit in a compliance account, the Administrator will assign
each TR SO 2 Group 1 allowance a unique identification number that will include digits identifying the year of the control period for which the TR SO 2 Group 1 allowance is allocated.

**§ 97.622 Submission of TR SO** 2 **Group 1**

**allowance transfers.**

(a) An authorized account representative seeking recordation of a

TR SO 2 Group 1 allowance transfer shall
submit the transfer to the Administrator.

(b) A TR SO 2 Group 1 allowance transfer shall be correctly submitted if:

(1) The transfer includes the following elements, in a format prescribed by the
Administrator:

(i) The account numbers established by the Administrator for both the transferor and transferee accounts;

(ii) The serial number of each TR SO 2 Group 1 allowance that is in the
transferor account and is to be transferred; and

(iii) The name and signature of the authorized account representative of the transferor account and the date signed;
and

(2) When the Administrator attempts to record the transfer, the transferor
account includes each TR SO 2 Group 1 allowance identified by serial number in
the transfer.

**§ 97.623 Recordation of TR SO** 2 **Group 1**

**allowance transfers.**

(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR SO 2 Group 1 allowance transfer, the Administrator
will record a TR SO 2 Group 1 allowance transfer by moving each TR SO 2 Group
1 allowance from the transferor account to the transferee account as specified by the request, provided that the transfer is correctly submitted under § 97.622.

(b)(1) A TR SO 2 Group 1 allowance
transfer that is submitted for recordation
after the allowance transfer deadline for a control period and that includes any

TR SO 2 Group 1 allowances allocated for any control period before such
allowance transfer deadline will not be
recorded until after the Administrator completes the deductions under § 97.624 for the control period immediately before such allowance
transfer deadline.

(2) A TR SO 2 Group 1 allowance
transfer that is submitted for recordation after the deadline for holding TR SO 2 Group 1 allowances described in § 97.625(b)(5) and that includes any TR

SO 2 Group 1 allowances allocated for a control period before the year of such
deadline will not be recorded until after the Administrator completes the deductions under § 97.625 for the control period immediately before the year of such deadline.

(c) Where a TR SO 2 Group 1 allowance transfer is not correctly submitted under § 97.622, the
Administrator will not record such
transfer.

(d) Within 5 business days of
recordation of a TR SO 2 Group 1 allowance transfer under paragraphs (a) and (b) of the section, the Administrator will notify the authorized account representatives of both the transferor
and transferee accounts.

(e) Within 10 business days of receipt
of a TR SO 2 Group 1 allowance transfer that is not correctly submitted under § 97.622, the Administrator will notify the authorized account representatives of both accounts subject to the transfer
of:

(1) A decision not to record the transfer, and

(2) The reasons for such nonrecordation.

**§ 97.624 Compliance with TR SO** 2 **Group 1**

**emissions limitation.**

(a) Availability for deduction for compliance. TR SO 2 Group 1 allowances
are available to be deducted for compliance with a source’s TR SO 2 Group 1 emissions limitation for a control period in a given year only if the

TR SO 2 Group 1 allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in the source’s compliance account as of the allowance
transfer deadline for such control period.

(b) Deductions for compliance . After the recordation, in accordance with § 97.623, of TR SO 2 Group 1 allowance transfers submitted by the allowance transfer deadline for a control period,
the Administrator will deduct from the compliance account TR SO 2 Group 1 allowances available under paragraph (a) of this section in order to determine
whether the source meets the TR SO 2 Group 1 emissions limitation for such control period, as follows:

(1) Until the amount of TR SO 2 Group 1 allowances deducted equals the
number of tons of total SO 2 emissions
from all TR SO 2 Group 1 units at the source for such control period; or

(2) If there are insufficient TR SO 2 Group 1 allowances to complete the deductions in paragraph (b)(1) of this section, until no more TR SO 2 Group 1 allowances available under paragraph (a) of this section remain in the compliance account.

(c)(1) Identification of TR SO 2 Group 1 allowances by serial number. The authorized account representative for a source’s compliance account may request that specific TR SO 2 Group 1 allowances, identified by serial number, in the compliance account be deducted
for emissions or excess emissions for a control period in accordance with paragraph (b) or (d) of this section. In order to be complete, such request shall be submitted to the Administrator by
the allowance transfer deadline for such control period and include, in a format prescribed by the Administrator, the
identification of the TR SO 2 Group 1 source and the appropriate serial
numbers.

(2) First-in, first-out. The
Administrator will deduct TR SO 2 Group 1 allowances under paragraph (b) or (d) of this section from the source’s compliance account in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the case of
identification of an insufficient amount
of TR SO 2 Group 1 allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following order:

(i) Any TR SO 2 Group 1 allowances
that were allocated to the units at the
source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR SO 2 Group 1 allowances that were allocated to any unit and
transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in
which the TR SO 2 Group 1 source has excess emissions, the Administrator will deduct from the source’s compliance
account an amount of TR SO 2 Group 1 allowances, allocated for the control period in the immediately following year, equal to two times the number of
tons of the source’s excess emissions.

(e) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraphs (b) and (d) of this section.

**§ 97.625 Compliance with TR SO** 2 **Group 1 assurance provisions.** 

(a) Availability for deduction. TR SO 2 Group 1 allowances are available to be deducted for compliance with the TR

SO 2 Group 1 assurance provisions for a control period in a given year by an
owner of one or more TR SO 2 Group 1 units in a State only if the TR SO 2 Group 1 allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in a compliance account, designated by the owner in accordance


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with paragraph (b)(4)(ii) of this section,
of one of the owner’s TR SO 2 Group 1
sources in the State as of the deadline established in paragraph (b)(5) of this

section.

(b) Deductions for compliance. The
Administrator will deduct TR SO 2 Group 1 allowances available under paragraph (a) of this section for compliance with the TR SO 2 Group 1 assurance provisions for a State for a control period in a given year in accordance with the following procedures:

(1) By June 1, 2015 and June 1 of each year thereafter, the Administrator will:

(i) Calculate, separately for each State,
the total amount of SO 2 emissions from
all TR SO 2 Group 1 units in the State during the control period in the year before the year of this calculation deadline and the amount, if any, by
which such total amount of NO X emissions exceeds the State assurance level as described in § 97.606(c)(2)(iii);
and

(ii) Promulgate a notice of availability
of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations
of the SO 2 emissions for each TR SO 2 Group 1 unit and of the amounts described in §§ 97.606(c)(2)(iii)(A) and (B) for each State.

(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of
this section.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each TR

SO 2 Group 1 unit and each State for the control period in the year involved are in accordance with § 97.606(c)(2)(iii) and §§ 97.606(b) and 97.630 through

97.635.

(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By August 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR SO 2 Group 1
sources with total SO 2 emissions exceeding the State assurance level for a control period, as described in § 97.606(c)(2)(iii): (i) By August 15 immediately after the promulgation of such notice, the designated representative of each TR

SO 2 Group 1 source in each such State shall submit a statement, in a format prescribed by the Administrator:

(A) Listing all the owners of each TR

SO 2 Group 1 unit at the source, explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of

‘‘ owner ’’ in § 97.602, and listing, separately for each unit, the percentage of the legal, equitable, leasehold, or
contractual reservation or entitlement for each such owner as of midnight of December 31 of the control period in the year involved; and

(B) For each TR SO 2 Group 1 unit at the source that operates during, but is
allocated no TR SO 2 Group 1 allowances for, the control period in the year involved, identifying whether the unit is a coal-fired boiler, simple combustion turbine, or combined cycle turbine cycle and providing the unit’s allowable SO 2 emission rate for such control period.

(ii) By September 15 immediately after the promulgation of such notice, the Administrator will calculate, for
each such State and each owner of one

or more TR SO 2 Group 1 units in the State and for the control period in the year involved, each owner’s share of the
total SO 2 emissions from all TR SO 2 Group 1 units in the State, each owner’s assurance level, and the amount (if any)
of TR SO 2 Group 1 allowances that each
owner must hold in accordance with the calculation formula in § 97.606(c)(2)(i) and will promulgate a notice of availability of the results of these
calculations.

(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability required in paragraph (b)(3)(ii) of this

section.

(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each owner for the control period in the year
involved are consistent with the SO 2 emissions for the relevant TR SO 2 Group 1 units as set forth in the notice required in paragraph (b)(2)(ii) of this section, the
definitions of ‘‘ owner ’’

, ‘‘ owner’s
assurance level ’’ , and ‘‘ owner’s share ’’ in § 97.602, and the calculation formula in § 97.606(c)(2)(i) and shall not raise any issues about any data used in the notice of data availability required in paragraph (b)(2)(ii) of this section.

(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section. By November 15 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that
the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(3)(iii)(A)
of this section.

(4) By December 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:

(i) Each owner identified, in such notice, as owning one or more TR SO 2 Group 1 units in a State and as being required to hold TR SO 2 Group 1 allowances shall designate the compliance account of one of the
sources at which such unit or units are located to hold such required TR SO 2 Group 1 allowances;

(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.

(5)(i) As of midnight of December 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount
of TR SO 2 Group 1 allowances, available for deduction under paragraph (a) of this section, equal to the amount the owner is required to hold as calculated by the Administrator and referenced in
such notice.

(ii) Notwithstanding the allowanceholding deadline specified in paragraph (b)(5)(i) of this section, if December 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day
thereafter.

(6) After December 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.623, of TR SO 2 Group 1 allowance transfers submitted by midnight of such date, the Administrator will deduct from each compliance account designated in accordance with paragraph (b)(4)(ii) of this section, TR

SO 2 Group 1 allowances available under paragraph (a) of this section, as follows:

(i) Until the amount of TR SO 2 Group 1 allowances deducted equals the


### 45434 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

amount that the owner designating the compliance account is required to hold as calculated by the Administrator and referenced in the notice required in paragraph (b)(3)(iii)(B) of this section; or

(ii) If there are insufficient TR SO 2 Group 1 allowances to complete the deductions in paragraph (b)(6)(i) of this section, until no more TR SO 2 Group 1 allowances available under paragraph (a) of this section remain in the compliance account.

(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice,
the amount of TR SO 2 Group 1 allowances that each owner is required
to hold in accordance with § 97.606(c)(2)(i) for the control period in the year involved shall continue to be such amount as calculated by the
Administrator and referenced in such notice required in paragraph (b)(3)(iii)(B) of this section, except as
follows:

(i) If any such data are revised by the
Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal
under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR SO 2 Group 1 allowances that owners are required to hold in
accordance with the calculation formula in § 97.606(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that—

(A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and

(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section. (ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the
Administrator will use the data as so
revised to recalculate the amounts of TR

SO 2 Group 1 allowances that owners are required to hold in accordance with the calculation formula in § 97.606(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that such litigation was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii)(B) of this section.

(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR SO 2 Group 1 allowances that an owner is required to hold for the control period in the year involved with regard to the State
involved—

(A) Where the amount of TR SO 2 Group 1 allowances that an owner is required to hold increases as a result of the use of all such revised data, the Administrator will establish a new,
reasonable deadline on which the owner
shall hold the additional amount of TR

SO 2 Group 1 allowances in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section. The owner’s failure to hold such additional amount, as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s failure to hold such additional amount, as required, as of the
new deadline shall be a violation of the
Clean Air Act. Each TR SO 2 Group 1
allowance that the owner fails to hold as required as of the new deadline, and each day in the control period in the year involved, shall be a separate
violation of the Clean Air Act. After such deadline, the Administrator will make the appropriate deductions from the compliance account.

(B) For an owner for which the
amount of TR SO 2 Group 1 allowances required to be held decreases as a result of the use of all such revised data, the Administrator will record, in the compliance account that the owner designated in accordance with paragraph (b)(4)(ii) of this section, an
amount of TR SO 2 Group 1 allowances equal to the amount of the decrease to the extent such amount was previously deducted from the compliance account under paragraph (b)(6) of this section (and has not already been restored to the compliance account) for the control period in the year involved. (C) Each TR SO 2 Group 1 allowance held and deducted under paragraph (b)(7)(iii)(A) of this section, or recorded under paragraph (b)(7)(iii)(B) of this section, as a result of recalculation of requirements under the TR SO 2 Group 1 assurance provisions for a control period in a given year must be a TR SO 2 Group 1 allowance allocated for a control period in the same or a prior

year.

(c)(1) Identification of TR SO 2 Group 1 allowances by serial number. The authorized account representative for each source’s compliance account designated in accordance with paragraph (b)(4)(ii) of this section may request that specific TR SO 2 Group 1 allowances, identified by serial number, in the compliance account be deducted in accordance with paragraph (b)(6) or (7) of this section. In order to be complete, such request shall be submitted to the Administrator by the allowance-holding deadline described in paragraph (b)(5) of this section and include, in a format prescribed by the Administrator, the identification of the compliance account and the appropriate
serial numbers.

(2) First-in, first-out. The
Administrator will deduct TR SO 2 Group 1 allowances under paragraphs (b)(6) and (7) of this section from each source’s compliance account designated under paragraph (b)(4)(ii) of this section in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the
case of identification of an insufficient
amount of TR SO 2 Group 1 allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following
order:

(i) Any TR SO 2 Group 1 allowances
that were allocated to the units at the
source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR SO 2 Group 1 allowances that were allocated to any unit and
transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraph (b) of this section.

**§ 97.626 Banking.**

(a) A TR SO 2 Group 1 allowance may
be banked for future use or transfer in a compliance account or a general account in accordance with paragraph (b) of this section.

(b) Any TR SO 2 Group 1 allowance that is held in a compliance account or a general account will remain in such


### 45435 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

account unless and until the TR SO 2 Group 1 allowance is deducted or transferred under § 97.611(c), § 97.623, § 97.624, § 97.625, 97.627, 97.628,
97.642, or 97.643.

**§ 97.627 Account error.**

The Administrator may, at his or her
sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.

**§ 97.628 Administrator’s action on**
**submissions.**

(a) The Administrator may review and conduct independent audits concerning any submission under the TR SO 2 Group 1 Trading Program and make appropriate adjustments of the
information in the submission.

(b) The Administrator may deduct TR

SO 2 Group 1 allowances from or transfer

TR SO 2 Group 1 allowances to a source’s compliance account based on the information in a submission, as adjusted under paragraph (a)(1) of this section, and record such deductions and
transfers.

**§ 97.629 [Reserved]**

**§ 97.630 General monitoring, recordkeeping, and reporting requirements.** 

The owners and operators, and to the extent applicable, the designated representative, of a TR SO 2 Group 1 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subparts F and G of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.602 and in § 72.2 of this chapter shall apply,
the terms ‘‘ affected unit, ’’ ‘‘ designated representative, ’’ and ‘‘ continuous emission monitoring system ’’ (or

‘‘ CEMS ’’ ) in part 75 of this chapter shall
be deemed to refer to the terms ‘‘ TR SO 2 Group 1 unit, ’’ ‘‘ designated representative, ’’ and ‘‘ continuous emission monitoring system ’’ (or

‘‘ CEMS ’’ ) respectively as defined in § 97.602, and the term ‘‘ newly affected

unit ’’ shall be deemed to mean ‘‘ newly
affected TR SO 2 Group 1 unit. ’’ The owner or operator of a unit that is not

a TR SO 2 Group 1 unit but that is monitored under § 75.16(b)(2) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a TR SO 2 Group 1 unit.

(a) Requirements for installation, certification, and data accounting. The owner or operator of each TR SO 2 Group
1 unit shall: (1) Install all monitoring systems required under this subpart for monitoring SO 2 mass emissions and individual unit heat input (including all systems required to monitor SO 2 concentration, stack gas moisture content, stack gas flow rate, CO 2 or O 2 concentration, and fuel flow rate, as applicable, in accordance with §§ 75.11 and 75.16 of this chapter);

(2) Successfully complete all certification tests required under § 97.631 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator shall meet the monitoring system certification and other requirements of paragraphs (a)(1) and (2) of this section on or before the following dates. The owner or operator shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.

(1) For the owner or operator of a TR

SO 2 Group 1 unit that commences commercial operation before July 1, 2011, by January 1, 2012.

(2) For the owner or operator of a TR

SO 2 Group 1 unit that commences commercial operation on or after July 1, 2011, by the later of the following dates:

(i) January 1, 2012; or (ii) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.

(3) For the owner or operator of a TR

SO 2 Group 1 unit for which
construction of a new stack or flue or
installation of add-on SO 2 emission controls is completed after the applicable deadline under paragraph (b)(1) or (2) of this section, by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on
which emissions first exit to the atmosphere through the new stack or
flue or add-on SO 2 emissions controls.

(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a TR opt-in application is
submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.641(c).

(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a TR SO 2 Group 1 opt-in unit, by the date on
which the TR SO 2 Group 1 opt-in unit enters the TR SO 2 Group 1 Trading Program as provided in § 97.641(h).

(c) Reporting data. The owner or operator of a TR SO 2 Group 1 unit that does not meet the applicable compliance date set forth in paragraph (b) of this section for any monitoring system under paragraph (a)(1) of this section shall, for each such monitoring system, determine, record, and report maximum potential (or, as appropriate, minimum potential) values for SO 2 concentration, stack gas flow rate, stack gas moisture content, fuel flow rate, and any other parameters required to
determine SO 2 mass emissions and heat input in accordance with § 75.31(b)(2) or (c)(3) of this chapter or section 2.4 of appendix D to part 75 of this chapter, as applicable.

(d) Prohibitions. (1) No owner or operator of a TR SO 2 Group 1 unit shall use any alternative monitoring system, alternative reference method, or any other alternative to any requirement of this subpart without having obtained prior written approval in accordance with § 97.635.

(2) No owner or operator of a TR SO 2 Group 1 unit shall operate the unit so as to discharge, or allow to be discharged, SO 2 emissions to the atmosphere without accounting for all
such emissions in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(3) No owner or operator of a TR SO 2 Group 1 unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording SO 2 mass emissions discharged into the atmosphere or heat input, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(4) No owner or operator of a TR SO 2 Group 1 unit shall retire or permanently
discontinue use of the continuous emission monitoring system, any component thereof, or any other approved monitoring system under this subpart, except under any one of the following circumstances:

(i) During the period that the unit is covered by an exemption under § 97.605 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the
Administrator for use at that unit that provides emission data for the same


### 45436 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

pollutant or parameter as the retired or discontinued monitoring system; or

(iii) The designated representative
submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.631(d)(3)(i).

(e) Long-term cold storage. The owner or operator of a TR SO 2 Group 1 unit is subject to the applicable provisions of § 75.4(d) of this chapter concerning units in long-term cold storage.

**§ 97.631 Initial monitoring system certification and recertification procedures.** 

(a) The owner or operator of a TR SO 2 Group 1 unit shall be exempt from the initial certification requirements of this section for a monitoring system under § 97.630(a)(1) if the following conditions

are met:

(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and

(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B and D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of
this section.

(b) The recertification provisions of this section shall apply to a monitoring system under § 97.630(a)(1) exempt from initial certification requirements under paragraph (a) of this section.

(c) [Reserved] (d) Except as provided in paragraph (a) of this section, the owner or operator
of a TR SO 2 Group 1 unit shall comply with the following initial certification and recertification procedures, for a continuous monitoring system ( i.e., a continuous emission monitoring system and an excepted monitoring system under appendix D to part 75 of this chapter) under § 97.630(a)(1). The owner or operator of a unit that qualifies to use the low mass emissions excepted monitoring methodology under § 75.19 of this chapter or that qualifies to use an alternative monitoring system under subpart E of part 75 of this chapter shall comply with the procedures in paragraph (e) or (f) of this section respectively.

(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under § 97.630(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.630(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.

(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.630(a)(1) that may significantly affect the ability of the system to accurately measure or
record SO 2 mass emissions or heat input rate or to meet the quality-assurance and quality-control requirements of § 75.21 of this chapter or appendix B to part 75 of this chapter, the owner or operator shall recertify the monitoring system in accordance with § 75.20(b) of this chapter. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit’s operation that may significantly change the stack flow or concentration profile, the owner or operator shall recertify each continuous emission monitoring system whose accuracy is potentially affected by the change, in accordance with § 75.20(b) of this chapter. Examples of changes to a continuous emission monitoring system that require recertification include: Replacement of the analyzer, complete replacement of an existing continuous emission monitoring system, or change in location or orientation of the sampling probe or site. Any fuel flowmeter system under § 97.630(a)(1) is subject to the recertification requirements in § 75.20(g)(6) of this chapter.

(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.630(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words

‘‘ certification ’’ and ‘‘ initial certification ’’ are replaced by the word

‘‘ recertification ’’ and the word ‘‘ certified ’’ is replaced by with the word

‘‘ recertified ’’

.

(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office
and the Administrator written notice of the dates of certification testing, in accordance with § 97.633.

(ii) Certification application. The designated representative shall submit
to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.

(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under
the TR SO 2 Group 1 Trading Program for a period not to exceed 120 days after receipt by the Administrator of the complete certification application for the monitoring system under paragraph (d)(3)(ii) of this section. Data measured and recorded by the provisionally certified monitoring system, in accordance with the requirements of part 75 of this chapter, will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that
the Administrator does not invalidate the provisional certification by issuing a notice of disapproval within 120 days of the date of receipt of the complete certification application by the
Administrator.

(iv) Certification application approval

process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter
and is included in the certification application will be deemed certified for
use under the TR SO 2 Group 1 Trading Program.

(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter,
then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day


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review period specified in paragraph (d)(3) of this section shall not begin before receipt of a complete certification application.

(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).

(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of
a monitor in accordance with § 97.632(b).

(v) Procedures for loss of certification.
If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section,
then:

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved SO 2 pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of

SO 2 and the maximum potential flow rate, as defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO 2 concentration or the minimum potential O 2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter. (B) The designated representative
shall submit a notification of
certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this

section.

(C) The owner or operator shall repeat
all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days
after the date of issuance of the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the
certification and recertification requirements in § 75.20(g) of this chapter.

(f) The designated representative of
each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.

**§ 97.632 Monitoring system out-of-control periods.** 

(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or appendix D to part 75 of this chapter.

(b) Audit decertification. Whenever both an audit of a monitoring system
and a review of the initial certification or recertification application reveal that any monitoring system should not have
been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.631 or the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission and at the time of the audit, the
Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit
shall be either a field audit or an audit of any information submitted to the Administrator or any permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data
from the date of issuance of the
notification of the revoked certification
status until the date and time that the owner or operator completes subsequently approved initial
certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable
initial certification or recertification procedures in § 97.631 for each disapproved monitoring system.

**§ 97.633 Notifications concerning monitoring.** 

The designated representative of a TR

SO 2 Group 1 unit shall submit written
notice to the Administrator in accordance with § 75.61 of this chapter.

**§ 97.634 Recordkeeping and reporting.**

(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in this section, the applicable recordkeeping and reporting requirements in subparts F and G of part 75 of this chapter, and the requirements of § 97.614(a).

(b) Monitoring plans. The owner or operator of a TR SO 2 Group 1 unit shall comply with requirements of § 75.62 of this chapter.

(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all
initial certification or recertification tests required under § 97.631, including the information required under § 75.63 of this chapter.

(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:

(1) The designated representative shall report the SO 2 mass emissions data and heat input data for the TR SO 2 Group 1 unit, in an electronic quarterly report in a format prescribed by the Administrator, for each calendar quarter beginning with:

(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering January 1, 2012 through March 31, 2012;

(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.630(b), unless that quarter is the third or fourth quarter of 2011, in which case reporting shall


### 45438 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

commence in the quarter covering January 1, 2012 through March 31, 2012;

(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a TR opt-in application is
submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.641(c); and

(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a TR

SO 2 Group 1 opt-in unit, the calendar quarter corresponding to the date on
which the TR SO 2 Group 1 opt-in unit
enters the TR SO 2 Group 1 Trading Program as provided in § 97.641(h).

(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.

(3) For TR SO 2 Group 1 units that are also subject to the Acid Rain Program,

TR NO X Annual Trading Program, or TR

NO X Ozone Season Trading Program, quarterly reports shall include the applicable data and information required by subparts F through H of part 75 of this chapter as applicable, in
addition to the SO 2 mass emission data, heat input data, and other information required by this subpart.

(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.

(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any
corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction. (ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of
this section.

(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully
monitored. The certification shall state
that:

(1) The monitoring data submitted
were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and

(2) For a unit with add-on SO 2 emission controls and for all hours
where SO 2 data are substituted in accordance with § 75.34(a)(1) of this chapter, the add-on emission controls were operating within the range of parameters listed in the quality assurance/quality control program under appendix B to part 75 of this chapter and the substitute data values do not systematically underestimate SO 2 emissions.

**§ 97.635 Petitions for alternatives to monitoring, recordkeeping, or reporting**  **requirements.**

(a) The designated representative of a

TR SO 2 Group 1 unit may submit a petition under § 75.66 of this chapter to the Administrator, requesting approval to apply an alternative to any requirement of §§ 97.630 through 97.634 or paragraph (5)(i) or (ii) of the
definition of ‘‘ owner’s share ’’ in § 97.602.

(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition, including, at a minimum, the following information:

(i) Identification of each unit and source covered by the petition;

(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;

(iii) A description and diagram of any equipment and procedures used in the proposed alternative;

(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the
alternative will be de minimis; and

(v) Any other relevant information that the Administrator may require.

(c) Use of an alternative to any requirement referenced in paragraph (a)
of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.

**§ 97.640 General requirements for TR SO** 2 **Group 1 opt-in units.**

(a) A TR SO 2 Group 1 opt-in unit must
be a unit that:

(1) Is located in a State; (2) Is not a TR SO 2 Group 1 unit under § 97.604;

(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and

(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.

(b) A TR SO 2 Group 1 opt-in unit shall
be deemed to be a TR SO 2 Group 1 unit for purposes of applying this subpart, except for §§ 97.605, 97.611, and 97.612.

(c) Solely for purposes of applying the requirements of §§ 97.613 through 97.618 and §§ 97.630 through 97.635, a unit for which a TR opt-in application
is submitted and not withdrawn and is not yet approved or disapproved under § 97.642 shall be deemed to be a TR SO 2 Group 1 unit.

(d) Any TR SO 2 Group 1 opt-in unit, and any unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved under § 97.642, located at
the same source as one or more TR SO 2 Group 1 units shall have the same designated representative and alternate designated representative as such TR

SO 2 Group 1 units.

**§ 97.641 Opt-in process.**

A unit meeting the requirements for a

TR SO 2 Group 1 opt-in unit in § 97.640(a) may become a TR SO 2 Group 1 opt-in unit only if, in accordance with this section, the designated representative of the unit submits a complete TR opt-in application for the unit and the Administrator approves the application.

(a) Applying to opt-in. The designated representative of the unit may submit a complete TR opt-in application for the unit at any time, except as provided under § 97.642(e). A complete TR opt-in application shall include the following elements in a format prescribed by the
Administrator:

(1) Identification of the unit and the source where the unit is located,


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including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, and unit identification number and type;

(2) A certification that the unit: (i) Is not a TR SO 2 Group 1 unit under § 97.604;

(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;

(iii) Vents all of its emissions to a stack; and

(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;

(3) A monitoring plan in accordance with §§ 97.630 through 97.635;

(4) A statement that the unit, if approved to become a TR SO 2 Group 1 unit under paragraph (g) of this section, may withdraw from the TR SO 2 Group 1 Trading Program only in accordance with § 97.642;

(5) A statement that the unit, if approved to become a TR SO 2 Group 1 unit under paragraph (g) of this section, is subject to, and the owners and operators of the unit must comply with, the requirements of § 97.643;

(6) A complete certificate of representation under § 97.616 consistent with § 97.640, if no designated representative has been previously designated for the source that includes the unit; and

(7) The signature of the designated representative and the date signed.

(b) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan submitted under paragraph (a)(3) of this section. The monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the SO 2 emission rate and heat input of the unit and all other applicable parameters are monitored and reported in accordance with §§ 97.630 through 97.635. A determination of sufficiency shall not be construed as acceptance or approval of the monitoring plan.

(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the monitoring plan is sufficient under paragraph (b) of this section, the owner or operator of the unit shall monitor and report the SO 2 emission rate and the heat input of the unit and all other applicable parameters, in accordance with §§ 97.630 through 97.635, starting
on the date of certification of the necessary monitoring systems under §§ 97.630 through 97.635 and continuing until the TR opt-in application submitted under paragraph (a) of this section is disapproved under this section or, if such TR opt-in application is approved, the date and
time when the unit is withdrawn from
the TR SO 2 Group 1 Trading Program in accordance with § 97.642.

(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which
the unit enters the TR SO 2 Group 1 Trading Program under paragraph (h) of this section, during which period monitoring system availability must not be less than 98 percent under §§ 97.630 through 97.635 and the unit must be in full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.

(2) To the extent the SO 2 emission rate and the heat input of the unit are monitored and reported in accordance with §§ 97.630 through 97.635 for one or more entire control periods, in addition to the control period under paragraph (c)(1)(ii) of this section, during which control periods monitoring system availability is not less than 98 percent under §§ 97.630 through 97.635 and the unit is in full compliance with any applicable State or Federal emissions or emissions-related requirements and which control periods begin not more than 3 years before the unit enters the

TR SO 2 Group 1 Trading Program under paragraph (h) of this section, such information shall be used as provided in paragraphs (e) and (f) of this section.

(d) Statement on compliance. After submitting to the Administrator all quarterly reports required for the unit under paragraph (c) of this section, the designated representative shall submit, in a format prescribed by the Administrator, to the Administrator a statement that, for the years covered by such quarterly reports, the unit was in full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.

(e) Baseline heat input. The unit’s baseline heat input shall equal:

(1) If the unit’s SO 2 emission rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s total heat input (in mmBtu) for such control period; or

(2) If the unit’s SO 2 emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, the average of the amounts of the unit’s total heat input (in mmBtu) for such control periods. (f) Baseline SO 2 emission rate. The
unit’s baseline SO 2 emission rate shall equal:

(1) If the unit’s SO 2 emission rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s SO 2 emission rate (in lb/mmBtu) for such control period;

(2) If the unit’s SO 2 emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of thissection, and the unit does not have addon SO 2 emission controls during any such control periods, the average of the
amounts of the unit’s SO 2 emission rate (in lb/mmBtu) for such control periods;

or (3) If the unit’s SO 2 emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, and the unit has add-on SO 2 emission controls during any such control periods, the average of the
amounts of the unit’s SO 2 emission rate (in lb/mmBtu) for such control periods during which the unit has add-on SO 2 emission controls.

(g) Review of TR opt-in application. (1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the
Administrator determines that the designated representative shows that the unit meets the requirements for a TR

SO 2 Group 1 opt-in unit in § 97.640, the element certified in paragraph (a)(2)(iv) of this section, and the monitoring and reporting requirements of paragraph (c) of this section, the Administrator willissue a written approval of the TR optin application for the unit. The written approve will state the unit’s baseline heat input and baseline SO 2 emission
rate. The Administrator will thereafter establish a compliance account for the
source that includes the unit unless the source already has a compliance

account.

(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines
that the unit cannot meet the requirements for a TR SO 2 Group 1 opt-in unit in § 97.640, the element certified in paragraph (a)(2)(iv) of this section, or the monitoring and reporting requirements in paragraph (c) of this section, the Administrator will issue a written disapproval of the TR opt-in application for the unit.

(h) Date of entry into TR SO 2 Group 1 Trading Program. A unit for which a


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TR opt-in application is approved under paragraph (g)(1) of this section shall
become a TR SO 2 Group 1 opt-in unit,
and a TR SO 2 Group 1 unit, effective as of the later of January 1, 2012, or January 1 of the first control period during which such approval is issued.

**§ 97.642 Withdrawal of TR SO** 2 **Group 1 opt-in unit from TR SO**  2 **Group 1 Trading Program.** 

A TR SO 2 Group 1 opt-in unit may
withdraw from the TR SO 2 Group 1 Trading Program only if, in accordance with this section, the designated representative of the unit submits a request to withdraw the unit and the Administrator issues a written approval of the request.

(a) Requesting withdrawal. In order to
withdraw the TR SO 2 Group 1 opt-in
unit from the TR SO 2 Group 1 Trading Program, the designated representative
of the unit shall submit to the Administrator a request to withdraw the unit effective as of midnight of December 31 of a specified calendar year, which date must be at least 4 years after December 31 of the year of the unit’s entry into the TR SO 2 Group 1 Trading Program under § 97.641(h). The request shall be in a format prescribed by the Administrator and shall be submitted no later than 90 days before the requested effective date of
withdrawal.

(b) Conditions for withdrawal. Before

a TR SO 2 Group 1 opt-in unit covered by the request to withdraw may
withdraw from the TR SO 2 Group 1 Trading Program, the following
conditions must be met:

(1) For the control period ending on
the date on which the withdrawal is to be effective, the source that includes the

TR SO 2 Group 1 opt-in unit must meet the requirement to hold TR SO 2 Group 1 allowances under §§ 97.624 and 97.625 and cannot have any excess

emissions.

(2) After the requirement under paragraph (b)(1) of this section is met,
the Administrator will deduct from the compliance account of the source that
includes the TR SO 2 Group 1 opt-in unit

TR SO 2 Group 1 allowances equal in
amount to and allocated for the same or a prior control period as any TR SO 2 Group 1 allowances allocated to the TR

SO 2 Group 1 opt-in unit under § 97.644 for any control period after the date on
which the withdrawal is to be effective.
If there are no other TR SO 2 Group 1 units at the source, the Administrator will close the compliance account, and the owners and operators of the TR SO 2 Group 1 opt-in unit may submit a TR

SO 2 Group 1 allowance transfer for any remaining TR SO 2 Group 1 allowances to another Allowance Management System account in accordance with §§ 97.622 and 97.623.

(c) Approving withdrawal. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full
amount of TR SO 2 Group 1 allowances required), the Administrator will issue a written approval of the request to withdraw, which will become effective as of midnight on December 31 of the calendar year for which the withdrawal was requested. The unit covered by the request shall continue to be a TR SO 2 Group 1 opt-in unit until the effective date of the withdrawal and shall comply with all requirements under the TR SO 2 Group 1 Trading Program concerning any control periods for which the unit

is a TR SO 2 Group 1 opt-in unit, even if such requirements arise or must be complied with after the withdrawal
takes effect.

(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR

SO 2 Group 1 opt-in unit.

(d) Reapplication upon failure to meet conditions of withdrawal. If the Administrator disapproves the request to withdraw, the designated representative of the unit may submit another request to withdraw in accordance with paragraphs (a) and (b)
of this section.

(e) Ability to reapply to the TR SO 2 Group 1 Trading Program. Once a TR

SO 2 Group 1 opt-in unit withdraws from
the TR SO 2 Group 1 Trading Program, the designated representative may not submit another opt-in application under § 97.641 for such unit before the date that is 4 years after the date on which
the withdrawal became effective.

**§ 97.643 Change in regulatory status.**

(a) Notification. If a TR SO 2 Group 1 opt-in unit becomes a TR SO 2 Group 1 unit under § 97.604, then the designated representative of the unit shall notify the Administrator in writing of such change in the TR SO 2 Group 1 opt-in unit’s regulatory status, within 30 days of such change.

(b) Administrator’s actions. (1) If a TR

SO 2 Group 1 opt-in unit becomes a TR

SO 2 Group 1 unit under § 97.604, the Administrator will deduct, from the compliance account of the source that
includes the TR SO 2 Group 1 opt-in unit
that becomes a TR SO 2 Group 1 unit under § 97.604, TR SO 2 Group 1 allowances equal in amount to and allocated for the same or a prior control period as: (i) Any TR SO 2 Group 1 allowances
allocated to the TR SO 2 Group 1 opt-in unit under § 97.644 for any control period starting after the date on which
the TR SO 2 Group 1 opt-in unit becomes

a TR SO 2 Group 1 unit under § 97.604;
and

(ii) If the date on which the TR SO 2 Group 1 opt-in unit becomes a TR SO 2 Group 1 unit under § 97.604 is not December 31, the TR SO 2 Group 1
allowances allocated to the TR SO 2 Group 1 opt-in unit under § 97.644 for the control period that includes the date
on which the TR SO 2 Group 1 opt-in
unit becomes a TR SO 2 Group 1 unit under § 97.604—

(A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

SO 2 Group 1 opt-in unit becomes a TR

SO 2 Group 1 unit under § 97.604, divided by the total number of days in the control period, and

(B) Rounded to the nearest allowance.
(2) The designated representative shall ensure that the compliance
account of the source that includes the

TR SO 2 Group 1 opt-in unit that
becomes a TR SO 2 Group 1 unit under § 97.604 contains the TR SO 2 Group 1 allowances necessary for completion of the deduction under paragraph (b)(1) of
this section.

(3)(i) For control periods starting after
the date on which the TR SO 2 Group 1 opt-in unit becomes a TR SO 2 Group 1 unit under § 97.604, the TR SO 2 Group 1 opt-in unit will be allocated TR SO 2 Group 1 allowances in accordance with § 97.612.

(ii) If the date on which the TR SO 2 Group 1 opt-in unit becomes a TR SO 2 Group 1 unit under § 97.604 is not December 31, the following amount of

TR SO 2 Group 1 allowances will be
allocated to the TR SO 2 Group 1 opt-in unit (as a TR SO 2 Group 1 unit) in accordance with § 97.612 for the control period that includes the date on which
the TR SO 2 Group 1 opt-in unit becomes

a TR SO 2 Group 1 unit under § 97.604:

(A) The amount of TR SO 2 Group 1
allowances otherwise allocated to the

TR SO 2 Group 1 opt-in unit (as a TR SO 2 Group 1 unit) in accordance with § 97.612 for the control period;

(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

SO 2 Group 1 opt-in unit becomes a TR

SO 2 Group 1 unit under § 97.604, divided by the total number of days in the control period; and

(C) Rounded to the nearest allowance.


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**§ 97.644 TR SO** 2 **Group 1 allowance**
**allocations to TR SO** 2 **Group 1 opt-in units.**

(a) Timing requirements. (1) When the TR opt-in application is approved for a unit under § 97.641(g), the
Administrator will issue TR SO 2 Group
1 allowances and allocate them to the unit for the control period in which the
unit enters the TR SO 2 Group 1 Trading Program under § 97.641(h), in accordance with paragraph (b) of this

section.

(2) By no later than October 31 of the control period after the control period in
which a TR SO 2 Group 1 opt-in unit
enters the TR SO 2 Group 1 Trading Program under § 97.641(h) and October 31 of each year thereafter, the
Administrator will issue TR SO 2 Group
1 allowances and allocate them to the

TR SO 2 Group 1 opt-in unit for the control period that includes such
allocation deadline and in which the

unit is a TR SO 2 Group 1 opt-in unit, in accordance with paragraph (b) of this

section.

(b) Calculation of allocation. For each control period for which a TR SO 2 Group 1 opt-in unit is to be allocated TR

SO 2 Group 1 allowances, the
Administrator will issue and allocate TR

SO 2 Group 1 allowances in accordance with the following procedures:

(1) The heat input (in mmBtu) used for calculating the TR SO 2 Group 1
allowance allocation will be the lesser
of:

(i) The TR SO 2 Group 1 opt-in unit’s baseline heat input determined under § 97.641(g); or

(ii) The TR SO 2 Group 1 opt-in unit’s heat input, as determined in accordance with §§ 97.630 through 97.635, for the immediately prior control period, except when the allocation is being calculated for the control period in
which the TR SO 2 Group 1 opt-in unit
enters the TR SO 2 Group 1 Trading Program under § 97.641(h).

(2) The SO 2 emission rate (in lb/ mmBtu) used for calculating TR SO 2 Group 1 allowance allocations will be
the lesser of:

(i) The TR SO 2 Group 1 opt-in unit’s
baseline SO 2 emission rate (in lb/ mmBtu) determined under § 97.641(g) and multiplied by 70 percent; or

(ii) The most stringent State or
Federal SO 2 emissions limitation applicable to the TR SO 2 Group 1 optin unit at any time during the control period for which TR SO 2 Group 1
allowances are to be allocated.

(3) The Administrator will issue TR

SO 2 Group 1 allowances and allocate
them to the TR SO 2 Group 1 opt-in unit in an amount equaling the heat input under paragraph (b)(1) of this section, multiplied by the SO 2 emission rate under paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded to
the nearest allowance.

(c) Recordation. (1) The Administrator will record, in the compliance account
of the source that includes the TR SO 2 Group 1 opt-in unit, the TR SO 2 Group
1 allowances allocated to the TR SO 2 Group 1 opt-in unit under paragraph (a)(1) of this section.

(2) By December 1 of the control period after the control period in which

a TR SO 2 Group 1 opt-in unit enters the

TR SO 2 Group 1 Trading Program under § 97.641(h) and December 1 of each year thereafter, the Administrator will record, in the compliance account of the
source that includes the TR SO 2 Group 1 opt-in unit, the TR SO 2 Group 1
allowances allocated to the TR SO 2 Group 1 opt-in unit under paragraph (a)(2) of this section.

38. Part 97 is amended by adding subpart DDDDD to read as follows:

**Subpart DDDDD—TR SO** 2 **Group 2 Trading Program** 

Sec. 97.701 Purpose.
97.702 Definitions. 97.703 Measurements, abbreviations, and

acronyms. 97.704 Applicability. 97.705 Retired unit exemption. 97.706 Standard requirements. 97.707 Computation of time. 97.708 Administrative appeal procedures. 97.709 [Reserved]

97.710 State SO 2 Group 2 trading budgets, new-unit set-asides, and variability
limits. 97.711 Timing requirements for TR SO 2 Group 2 allowance allocations.

97.712 TR SO 2 Group 2 allowance
allocations for new units. 97.713 Authorization of designated representative and alternate designated representative. 97.714 Responsibilities of designated representative and alternate designated representative. 97.715 Changing designated representative and alternate designated representative; changes in owners and operators. 97.716 Certificate of representation. 97.717 Objections concerning designated representative and alternate designated representative. 97.718 Delegation by designated representative and alternate designated representative. 97.719 [Reserved]
97.720 Establishment of Allowance Management System accounts.
97.721 Recordation of TR SO 2 Group 2
allowance allocations.
97.722 Submission of TR SO 2 Group 2
allowance transfers.
97.723 Recordation of TR SO 2 Group 2
allowance transfers. 97.724 Compliance with TR SO 2 Group 2
emissions limitation. 97.725 Compliance with TR SO 2 Group 2 assurance provisions. 97.726 Banking.

97.727 Account error.
97.728 Administrator’s action on
submissions. 97.729 [Reserved] 97.730 General monitoring, recordkeeping, and reporting requirements. 97.731 Initial monitoring system
certification and recertification procedures. 97.732 Monitoring system out-of-control periods. 97.733 Notifications concerning monitoring. 97.734 Recordkeeping and reporting.
97.735 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements. 97.740 General requirements for TR SO 2 Group 2 opt-in units. 97.741 Opt-in process.
97.742 Withdrawal of TR SO 2 Group 2 optin unit from TR SO 2 Group 2 Trading Program. 97.743 Change in regulatory status.

97.744 TR SO 2 Group 2 allowance
allocations to TR SO 2 Group 2 opt-in

units.

**Subpart DDDDD—TR SO** 2 **Group 2 Trading Program** 

**§ 97.701 Purpose.**

This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) SO 2 Group 2 Trading Program, under section 110 of the Clean Air Act and § 52.38(b) of this chapter, as a means of mitigating interstate transport of fine particulates and nitrogen oxides.

**§ 97.702 Definitions.**

The terms used in this subpart shall have the meanings set forth in this
section as follows:

Acid Rain Program means a multistate SO 2 and NO X air pollution control and emission reduction program established by the Administrator under title IV of the Clean Air Act and parts 72 through 78 of this chapter.

Administrator means the
Administrator of the United States Environmental Protection Agency or the
Director of the Clean Air Markets Division (or its successor) of the United
States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.

Allocate or allocation means, with regard to TR SO 2 Group 2 allowances, the determination by the Administrator
of the amount of such TR SO 2 Group 2 allowances to be initially credited to a

TR SO 2 Group 2 source or a new unit
set-aside.

Allowable SO 2 emission rate means, with regard to a unit, the SO 2 emission rate limit that is applicable to the unit


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and covers the longest averaging period not exceeding one year.

Allowance Management System means the system by which the Administrator records allocations, deductions, and transfers of TR SO 2 Group 2 allowances under the TR SO 2 Group 2 Trading Program. Such allowances are allocated, held, deducted, or transferred only as whole
allowances. The Allowance Management System is a component of the CAMD Business System, which is the system used by the Administrator to
handle TR SO 2 Group 2 allowances and
data related to SO 2 emissions.

Allowance Management System

account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, holding, transfer, or deduction of TR

SO 2 Group 2 allowances.

Allowance transfer deadline means, for a control period, midnight of March 1 (if it is a business day), or midnight of the first business day thereafter (if March 1 is not a business day), immediately after such control period and is the deadline by which a TR SO 2 Group 2 allowance transfer must be
submitted for recordation in a TR SO 2 Group 2 source’s compliance account in
order to be available for use in complying with the source’s TR SO 2 Group 2 Annual emissions limitation for such control period in accordance with § 97.724.

Alternate designated representative means, for a TR SO 2 Group 2 source and
each TR SO 2 Group 2 unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with this subpart, to act on behalf of the designated representative in matters pertaining to the TR SO 2 Group 2 Trading Program. If the TR SO 2 Group 2 source is also subject to the Acid Rain Program, TR NO X Annual Season Trading Program, or TR NO X Ozone Season Trading Program, then this natural person shall be the same natural person as the alternate designated representative as defined in § 72.2 of this chapter, § 97.402, or § 97.502 respectively.

Authorized account representative means, with regard to a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of TR SO 2 Group 2 allowances held in the general account and, with regard to a TR SO 2 Group 2 source’s compliance account, the designated representative of the

source.

Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a
continuous record of the measured parameters in the measurement units required by this subpart.

Biomass means— (1) Any organic material grown for the purpose of being converted to energy;

(2) Any organic byproduct of agriculture that can be converted into

energy; or

(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from
other material that is nonmerchantable for other purposes, and that is;

(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct
from conversion of trees to merchantable material; or

(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.

Boiler means an enclosed fossil- or
other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other
medium.

Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

Certifying official means a natural person who is:

(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision making functions for the corporation;

(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or

(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking
elected official.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.

Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.

Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

Coal-fired means combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during 1990 or any year thereafter.

Cogeneration system means an integrated group, at a source, of equipment (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 electricity through the sequential use of energy.

Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine—

(1) Operating as part of a cogeneration system; and

(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—

(i) For a topping-cycle unit, (A) Useful thermal energy not less than 5 percent of total energy output;
and

(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.

(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;

(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler;
and

(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and thecogeneration system meets on a systemwide basis the requirement in paragraph(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such requirement during that calendar year.

Combustion turbine means an enclosed device comprising:

(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from
the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and

(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated


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duct burner, heat recovery steam generator, and steam turbine.

Commence commercial operation means, with regard to a unit:

(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.705.

(i) For a unit that is a TR SO 2 Group 2 unit under § 97.704 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such
date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit that is a TR SO 2 Group 2 unit under § 97.704 on the later of November 15, 1990 or the date the unit commences commercial operation as defined in the introductory text of paragraph (1) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for
commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.705, for a unit that is not a TR

SO 2 Group 2 unit under § 97.704 on the later of November 15, 1990 or the date
the unit commences commercial operation as defined in introductory text of paragraph (1) of this definition, the
unit’s date for commencement of commercial operation shall be the date
on which the unit becomes a TR SO 2 Group 2 unit under § 97.704.

(i) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source),
such date shall remain the date of
commencement of commercial operation of the unit, which shall
continue to be treated as the same unit.

(ii) For a unit with a date for
commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit’s date of
commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.

Commence operation means, with regard to a unit:

(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit’s
combustion chamber.

(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source)
after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be
treated as the same unit.

(3) For a unit that is replaced by a unit
at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.

Common stack means a single flue through which emissions from 2 or
more units are exhausted.

Compliance account means an Allowance Management System account, established by the
Administrator for a TR SO 2 Group 2 source under this subpart, in which any

TR SO 2 Group 2 allowance allocations
for the TR SO 2 Group 2 units at the
source are recorded and in which are held any TR SO 2 Group 2 allowances available for use for a control period in complying with the source’s TR SO 2 Group 2 emissions limitation in accordance with § 97.724 and the TR

SO 2 Group 2 assurance provisions in accordance with § 97.725.

Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent
record of SO 2 emissions, stack gas volumetric flow rate, stack gas moisture content, and O 2 or CO 2 concentration (as applicable), in a manner consistent with part 75 of this chapter and §§ 97.730 through 97.735. The following systems are the principal types of continuous emission monitoring systems:

(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A SO 2 monitoring system, consisting of a SO 2 pollutant
concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of SO 2 emissions, in parts per million (ppm);

(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H 2 O;

(4) A CO 2 monitoring system, consisting of a CO 2 pollutant concentration monitor (or an O 2 monitor plus suitable mathematical equations
from which the CO 2 concentration is derived) and an automated data acquisition and handling system and providing a permanent, continuous
record of CO 2 emissions, in percent CO 2 ; and

(5) An O 2 monitoring system, consisting of an O 2 concentration
monitor and an automated data acquisition and handling system and providing a permanent, continuous
record of O 2 , in percent O 2

.

Control period means the period starting January 1 of a calendar year, except as provided in § 97.706(c)(3), and ending on December 31 of the same year, inclusive.

Designated representative means, for

a TR SO 2 Group 2 source and each TR

SO 2 Group 2 unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with this subpart, to represent and legally bind each owner and operator in matters pertaining to the

TR SO 2 Group 2 Trading Program. If the

TR SO 2 Group 2 source is also subject to the Acid Rain Program, TR NO X Annual Trading Program, or TR NO X Ozone Season Trading Program, then this natural person shall be the same natural person as the designated representative, as defined in § 72.2 of this chapter, § 97.402, or § 97.502 respectively.

Emissions means air pollutants
exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart.

Excess emissions means any ton of

SO 2 emitted from the TR SO 2 Group 2

units at a TR SO 2 Group 2 source during a control period that exceeds the TR SO 2 Group 2 emissions limitation for the

source.

Fossil fuel means—


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(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or

(2) For purposes of applying §§ 97.704(b)(2)(i)(B), 97.704(b)(2)(ii)(B), and 97.704(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating
useful heat.

Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 1990 or any calendar year
thereafter.

Fuel oil means any petroleum-based fuel (including diesel fuel or petroleum derivatives such as oil tar) and any recycled or blended petroleum products or petroleum by-products used as a fuel whether in a liquid, solid, or gaseous

state.

General account means an Allowance Management System account, established under this subpart, that is not a compliance account.

Generator means a device that produces electricity.

Gross electrical output means, with regard to a unit, electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Heat input means, with regard to a unit for a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the designated representative and as modified by the
Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.

Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the
fuel.

Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:

(1) For the life of the unit; (2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination;

or (3) For a period no less than 25 years or 70 percent of the economic useful life
of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as of
the initial installation of the unit as specified by the manufacturer of the

unit.

Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.

Nameplate capacity means, starting
from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of such completion as specified by the person conducting the physical change.

Newly affected TR SO 2 Group 2 unit
means a unit that was not a TR SO 2 Group 2 unit when it began operating
but that thereafter becomes a TR SO 2 Group 2 unit.

Operate or operation means, with regard to a unit, to combust fuel.

Operator means any person who operates, controls, or supervises a TR

SO 2 Group 2 unit or a TR SO 2 Group 2 source and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit

or source.

Owner means, with regard to a TR SO 2 Group 2 source or a TR SO 2 Group 2 unit at a source respectively, any of the following persons:

(1) Any holder of any portion of the legal or equitable title in a TR SO 2 Group 2 unit at the source or the TR SO 2 Group 2 unit;

(2) Any holder of a leasehold interest

in a TR SO 2 Group 2 unit at the source
or the TR SO 2 Group 2 unit, provided that, unless expressly provided for in a leasehold agreement, ‘‘ owner ’’ shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly)
on the revenues or income from such TR

SO 2 Group 2 unit;

(3) Any purchaser of power from a TR

SO 2 Group 2 unit at the source or the

TR SO 2 Group 2 unit under a life-of-theunit, firm power contractual arrangement;

(4) Provided that, for purposes of applying the TR SO 2 Group 2 assurance provisions in §§ 97.706(c)(2) and 97.725, if one or more owners (as defined in paragraphs (1) through (3) of this definition) of one or more TR SO 2 Group 2 units in a State are wholly owned by another, common owner, all such owners shall be treated collectively as a single owner in the State.

Owner’s assurance level means: (1) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.706(c)(2)(iii)(A) and not as described in § 97.706(c)(2)(iii)(B), the
owner’s share of the State SO 2 Group 2 trading budget with the one-year variability limit for the State for such control period; or

(2) With regard to a State and control period for which the State assurance
level is exceeded as described in § 97.706(c)(2)(iii)(B), the owner’s share
of the State SO 2 Group 2 trading budget with the three-year variability limit for the State for such control period.

Owner’s share means: (1) With regard to a total amount of

SO 2 emissions from all TR SO 2 Group 2 units in a State during a control period, the total tonnage of SO 2 emissions during such control period from all of
the owner’s TR SO 2 Group 2 units in the State;

(2) With regard to a State SO 2 Group 2 trading budget with a one-year variability limit for a control period, the amount (rounded to the nearest allowance) equal to the total amount of

TR SO 2 Group 2 allowances allocated for such control period to all of the

owner’s TR SO 2 Group 2 units in the State, multiplied by the sum of the State

SO 2 Group 2 trading budget under § 97.710(a) and the State’s one-year variability limit under § 97.710(b) and divided by such State SO 2 Group 2 trading budget;

(3) With regard to a State SO 2 Group 2 trading budget with a three-year


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variability limit for a control period, the amount (rounded to the nearest allowance) equal to the total amount of

TR SO 2 Group 2 allowances allocated for such control period to all of the

owner’s TR SO 2 Group 2 units in the State, multiplied by the sum of the State

SO 2 Group 2 trading budget under § 97.710(a) and the State’s three-year variability limit under § 97.710(b) and divided by such State SO 2 Group 2 trading budget;

(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of SO 2 emissions and of TR

SO 2 Group 2 allowances allocated for a control period, with regard to such unit, used in determining each owner’s share shall be the amount (rounded to the nearest ton and the nearest allowance) equal to the unit’s SO 2 emissions and allocation of such allowances, respectively, for such control period multiplied by the percentage of ownership in the unit that the owner’s legal, equitable, leasehold, or
contractual reservation or entitlement in the unit comprises as of December 31 of such control period;

(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which

SO 2 mass emissions are reported for a control period for a year, the amount of tonnage of each unit’s SO 2 emissions used in determining each owner’s share for such control period shall be:

(i) The amount (rounded to the nearest ton) of SO 2 emissions reported at the common stack multiplied by the quotient of such unit’s heat input for such control period divided by the total heat input reported from the common stack for such control period;

(ii) An amount determined in accordance with a methodology that the
Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the
Administrator determines will be de minimis; or

(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.735; and

(6) Provided that, in the case of a unit that operates during, but is allocated no

TR SO 2 Group 2 allowances for, a control period, the unit shall be treated, solely for purposes of this definition, as being allocated an amount (rounded to the nearest allowance) of TR SO 2 Group 2 allowances for such control period equal to the lesser of—

(i) The unit’s allowable SO 2 emission rate (in lb per MWe) applicable to such control period, multiplied by a capacity factor of 0.84 (if the unit is a coal-fired boiler), 0.15 (if the unit is a simple combustion turbine), or 0.66 (if the unit is a combined cycle turbine), multiplied by the unit’s maximum hourly load as reported in accordance with this subpart and by 8,760 hours/control period, and divided by 2,000 lb/ton; or

(ii) For a unit listed in appendix A to this subpart, the sum of the unit’s SO 2 emissions in the control period in the last three years during which the unit operated during the control period, divided by three.

Permanently retired means, with regard to a unit, a unit that is
unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.

Permitting authority means

‘‘ permitting authority ’’ as defined in §§ 70.2 and 71.2 of this chapter.

Potential electrical output capacity means 33 percent of a unit’s maximum design heat input, divided by 3,413 Btu/ kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.

Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of
business.

Recordation, record, or recorded means, with regard to TR SO 2 Group 2 allowances, the moving of TR SO 2 Group 2 allowances by the Administrator into, out of, or between Allowance Management System accounts, for purposes of allocation, transfer, or deduction.

Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.

Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used
instead of the demolished or retired unit (the replaced unit).

Sequential use of energy means: (1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application

or process; or

(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.

Serial number means, for a TR SO 2 Group 2 allowance, the unique identification number assigned to each TR SO 2 Group 2 allowance by the
Administrator.

Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion
turbine that is a ‘‘ solid waste

incineration unit ’’ as defined in section 129(g)(1) of the Clean Air Act.

Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the
definition of ‘‘ major source ’’

, ‘‘ stationary

source ’’ , or ‘‘ source ’’ as set forth and implemented in a title V operating permit program or any other program
under the Clean Air Act.

State means one of the States or the District of Columbia that is subject to
the TR SO 2 Group 2 Trading Program pursuant to § 52.38(c) of this chapter.

Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(1) In person; (2) By United States Postal Service; or (3) By other means of dispatch or transmission and delivery;

(4) Provided that compliance with any

‘‘ submission ’’ or ‘‘ service ’’ deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.

Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.

Total energy input means total energy of all forms supplied to a unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as
follows:

LHV = HHV ¥ 10.55 (W + 9H)

Where LHV = lower heating value of the form of energy in Btu/lb, HHV = higher heating value of the form of energy in Btu/lb, W = weight % of moisture in the form of energy, and H = weight % of hydrogen in the form of

energy. Total energy output means the sum of useful power and useful thermal energy produced by the unit.

TR NO X Annual Trading Program
means a multi-state NO X air pollution control and emission reduction program established by the Administrator in


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accordance with subpart AAAAA and 52.37(a) of this chapter, as a means of mitigating interstate transport of fine particulates and NO X.

TR NO X Ozone Season Trading Program means a multi-state NO X air pollution control and emission reduction program established by the
Administrator in accordance with subpart BBBBB of this part and 52.37(b) of this chapter, as a means of mitigating interstate transport of ozone and NO X.

TR SO 2 Group 2 allowance means a limited authorization issued and allocated by the Administrator under this subpart to emit one ton of SO 2 during a control period of the specified calendar year for which the authorization is allocated or of any calendar year thereafter under the TR

SO 2 Group 2 Trading Program.

TR SO 2 Group 2 allowance deduction

or deduct TR SO 2 Group 2 allowances means the permanent withdrawal of TR

SO 2 Group 2 allowances by the Administrator from a compliance

account, e.g., in order to account for compliance with the TR SO 2 Group 2
emissions limitation or assurance provisions.

TR SO 2 Group 2 allowances held or hold TR SO 2 Group 2 allowances means the TR SO 2 Group 2 allowances treated
as included in an Allowance Management System account as of a specified point in time because at that time they:

(1) Have been recorded by the
Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR SO 2 Group 2 allowance transfer in accordance with this subpart;
and

(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR SO 2 Group 2
allowance transfer in accordance with this subpart.

TR SO 2 Group 2 emissions limitation means, for a TR SO 2 Group 2 source, the tonnage of SO 2 emissions authorized in a control period by the TR SO 2 Group
2 allowances available for deduction for the source under § 97.724(a) for such control period.

TR SO 2 Group 2 source means a source that includes one or more TR

SO 2 Group 2 units.

TR SO 2 Group 2 Trading Program
means a multi-state SO 2 air pollution control and emission reduction program established by the Administrator in accordance with this subpart and 52.38(c) of this chapter, as a means of mitigating interstate transport of fine particulates and SO 2. TR SO 2 Group 2 unit means a unit that is subject to the TR SO 2 Group 2 Trading Program under § 97.704.

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary,
fossil-fuel-fired combustion device.

Unit operating day means a calendar day in which a unit combusts any fuel.

Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.

Useful power means electricity or mechanical energy that a unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or
treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means thermal energy that is:

(1) Made available to an industrial or commercial process (not a power production process), excluding any heat
contained in condensate return or makeup water;

(2) Used in a heating application ( e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application ( i.e., in an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to

customers.

**§ 97.703 Measurements, abbreviations, and acronyms.** 

Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:

Btu—British thermal unit

CO 2 —carbon dioxide

H 2 O—water
hr—hour
kW—kilowatt electrical
kWh—kilowatt hour lb—pound
mmBtu—million Btu MWe—megawatt electrical MWh—megawatt hour

NO X —nitrogen oxides

O 2 —oxygen ppm—parts per million scfh—standard cubic feet per hour

SO 2 —sulfur dioxide

yr—year

**§ 97.704 Applicability.**

(a) Except as provided in paragraph (b) of this section:

(1) The following units in a State shall
be TR SO 2 Group 2 units, and any
source that includes one or more such
units shall be a TR SO 2 Group 2 source, subject to the requirements of this subpart: 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 chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a

TR SO 2 Group 2 unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the
unit shall become a TR SO 2 Group 2 unit as provided in paragraph (a)(1) of
this section on the first date on which
it both combusts fossil fuel and serves such generator.

(b) Any unit in a State that otherwise

is a TR SO 2 Group 2 unit under paragraph (a) of this section and that meets the requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR SO 2 Group 2 unit:

(1)(i) Any unit: (A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and

(B) Not serving at any time, since thelater of November 15, 1990 or the startup of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system
for sale.

(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the
unit shall become a TR SO 2 Group 2 unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of paragraph (b)(1)(i)(B) of this section.

(2)(i) Any unit commencing operation before January 1, 1985:

(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average annual fuel consumption of fossil fuel for 1985– 1987 less than 20 percent (on a Btu


### 45447 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(ii) Any unit commencing operation on or after January 1, 1985:

(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and

(B) With an average annual fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).

(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a

TR SO 2 Group 2 unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a solid waste incineration unit or January 1 after the first 3 consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of fossil fuel of 20 percent or more.

(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR SO 2 Group 2 Trading Program to the unit or other equipment.

(1) Petition content. The petition shall be in writing and include the
identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying
official: ‘‘ I am authorized to make this
submission on behalf of the owners and operators of the unit or other equipment
for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR SO 2 Group 2 Trading Program to the unit or other equipment shall be binding on any permitting authority unless the
Administrator determines that the petition or other documents or information provided in connection with the petition contained significant,
relevant errors or omissions.

**§ 97.705 Retired unit exemption.**

(a)(1) Any TR SO 2 Group 2 unit that is permanently retired and is not a TR

SO 2 Group 2 opt-in unit shall be exempt from § 97.706(b) and (c)(1), § 97.724, and §§ 97.730 through 97.735.

(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR SO 2 Group 2 unit is permanently retired. Within 30 days of the unit’s permanent retirement, the designated representative shall submit a statement
to the Administrator. The statement shall state, in a format prescribed by the Administrator, that the unit was permanently retired on a specified date and will comply with the requirements of paragraph (b) of this section.

(b) Special provisions. (1) A unit exempt under paragraph (a) of this section shall not emit any SO 2 , starting on the date that the exemption takes
effect.

(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR

SO 2 Group 2 Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect.

(4) A unit exempt under paragraph (a) of this section shall lose its exemption
on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.

**§ 97.706 Standard requirements.**

(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.713 through 97.718.

(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each TR

SO 2 Group 2 source and each TR SO 2 Group 2 unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of §§ 97.730 through 97.735.

(2) The emissions data determined in accordance with §§ 97.730 through
97.735 shall be used to calculate
allocations of TR SO 2 Group 2 allowances under §§ 97.711(a)(2) and (b)
and 97.712 and to determine compliance with the TR SO 2 Group 2
emissions limitation and assurance provisions under paragraph (c) of this section, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location
determined in accordance with §§ 97.730 through 97.735 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be

zero.

(c) SO 2 emissions requirements . (1)

TR SO 2 Group 2 emissions limitation. (i)
As of the allowance transfer deadline for a control period, the owners and operators of each TR SO 2 Group 2
source and each TR SO 2 Group 2 unit at the source shall hold, in the source’s compliance account, TR SO 2 Group 2
allowances available for deduction for such control period under § 97.724(a) in
an amount not less than the tons of total

SO 2 emissions for such control period
from all TR SO 2 Group 2 units at the

source.


### 45448 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

(ii) If a TR SO 2 Group 2 source emits

SO 2 during any control period in excess
of the TR SO 2 Group 2 emissions limitation set forth in paragraph (c)(1)(i) of this section, then:

(A) The owners and operators of the
source and each TR SO 2 Group 2 unit
at the source shall hold the TR SO 2 Group 2 allowances required for deduction under § 97.724(d) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act; and

(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.

(2) TR SO 2 Group 2 assurance provisions. (i) If the total amount of SO 2 emissions from all TR SO 2 Group 2 units in a State during a control period in 2014 or any year thereafter exceeds
the State assurance level as described in paragraph (c)(2)(iii) of this section, then
each owner whose share of such SO 2 emissions during such control period
exceeds the owner’s assurance level for the State and such control period shall hold, in a compliance account designated by the owner in accordance with § 97.725(b)(4)(ii), TR SO 2 Group 2
allowances available for deduction for such control period under § 97.725(a) in an amount equal to the product, as determined by the Administrator in accordance with § 97.725(b), of multiplying—

(A) The quotient (rounded to the nearest whole number) of the amount by
which the owner’s share of such SO 2 emissions exceeds the owner’s assurance level divided by the sum of the amounts, determined for all such owners, by which each owner’s share of
such SO 2 emissions exceeds that owner’s assurance level; and

(B) The amount by which total SO 2 emissions for all TR SO 2 Group 2 units in the State for such control period
exceed the State assurance level as
determined in accordance with paragraph (c)(2)(iii) of this section.

(ii) The owner shall hold the TR SO 2 Group 2 allowances required under paragraph (c)(2)(i) of this section, as of midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such control period.

(iii) The total amount of SO 2 emissions from all TR SO 2 Group 2 units in a State during a control period in 2014 or any year thereafter exceeds
the State assurance level:

(A) If such total amount of SO 2 emissions exceeds the sum, for such control period, of the State SO 2 Group 2 trading budget and the State’s oneyear variability limit under § 97.710(b);

or (B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount
of SO 2 emissions and the total amounts
of SO 2 emissions from all TR SO 2 Group 2 units in the State during the control periods in the immediately preceding two years exceeds the sum, for such control period, of the State SO 2 Group2 trading budget and the State’s threeyear variability limit under § 97.710(b);

(C) Provided that the amount by
which such total amount of SO 2 emissions exceeds the State assurance level shall be the greater of the amounts
of the exceedance calculated under paragraph (c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of this

section.

(iv) It shall not be a violation of this subpart or of the Clean Air Act if the
total amount of SO 2 emissions from all

TR SO 2 Group 2 units in a State during a control period exceeds the State
assurance level or if an owner’s share of
total SO 2 emissions from the TR SO 2 Group 2 units in a State during a control period exceeds the owner’s assurance
level.

(v) To the extent an owner fails to
hold TR SO 2 Group 2 allowances for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section,

(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and

(B) Each TR SO 2 Group 2 allowance
that the owner fails to hold for a control period in accordance with paragraphs (c)(2)(i) and (ii) of this section and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.

(3) Compliance periods. A TR SO 2 Group 2 unit shall be subject to the requirements:

(i) Under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2012 or the deadline for meeting the unit’s monitor certification requirements under § 97.730(b) and for each control period thereafter; and

(ii) Under paragraph (c)(2) of this section for the control period starting on the later of January 1, 2014 or the deadline for meeting the unit’s monitor certification requirements under § 97.730(b) and for each control period
thereafter.

(4) Vintage of deducted allowances. A

TR SO 2 Group 2 allowance shall not be deducted, for compliance with the requirements under paragraphs (c)(1) and (2) of this section, for a control period in a calendar year before the year
for which the TR SO 2 Group 2
allowance was allocated.

(5) Allowance Management System requirements. Each TR SO 2 Group 2 allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with this subpart.

(6) Limited authorization. (i) A TR

SO 2 Group 2 allowance is a limited
authorization to emit one ton of SO 2 in
accordance with the TR SO 2 Group 2 Trading Program.

(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to
terminate or limit such authorization to
the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean

Air Act.

(7) Property right. A TR SO 2 Group 2 allowance does not constitute a property right.

(d) Title V Permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction,
or transfer of TR SO 2 Group 2
allowances in accordance with this subpart.

(2) A description of whether a unit is required to monitor and report SO 2 emissions using a continuous emission monitoring system (under §§ 75.10, 75.11, and 75.16 of this chapter), an excepted monitoring system (under appendix D to part 75 of this chapter), a low mass emissions excepted monitoring methodology (under § 75.19 of this chapter), or an alternative monitoring system (under subpart E of part 75 of this chapter) in accordance with §§ 97.730 through 97.735 may be added to, or changed in, a title V permit using minor permit modification procedures in accordance with §§ 70.7(e)(2) and 71.7(e)(1) of this chapter, provided that the requirements applicable to the described monitoring and reporting (as added or changed, respectively) are already incorporated in such permit. This paragraph explicitly provides that the addition of, or change to, a unit’s description as described in the prior sentence is eligible for minor permit modification procedures in accordance with §§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.

(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each TR SO 2 Group 2
source and each TR SO 2 Group 2 unit at the source shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a


### 45449 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by
the Administrator.

(i) The certificate of representation under § 97.716 for the designated representative for the source and each

TR SO 2 Group 2 unit at the source and
all documents that demonstrate the
truth of the statements in the certificate of representation; provided that the
certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of
the submission of a new certificate of representation under § 97.716 changing the designated representative.

(ii) All emissions monitoring information, in accordance with this subpart.

(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR SO 2 Group 2 Trading Program, including any monitoring plans and monitoring system certification and recertification applications.

(2) The designated representative of a

TR SO 2 Group 2 source and each TR

SO 2 Group 2 unit at the source shall make all submissions required under
the TR SO 2 Group 2 Trading Program, including any submissions required for compliance with the TR SO 2 Group 2 assurance provisions. This requirement does not change, create an exemption from, or otherwise affect the responsible official submission requirements under a title V operating permit program in parts 70 and 71 of this chapter.

(f) Liability. (1) Any provision of the

TR SO 2 Group 2 Trading Program that applies to a TR SO 2 Group 2 source or the designated representative of a TR

SO 2 Group 2 source shall also apply to the owners and operators of such source

and of the TR SO 2 Group 2 units at the

source.

(2) Any provision of the TR SO 2 Group 2 Trading Program that applies to

a TR SO 2 Group 2 unit or the designated representative of a TR SO 2 Group 2 unit shall also apply to the owners and operators of such unit.

(g) Effect on other authorities. No provision of the TR SO 2 Group 2 Trading Program or exemption under § 97.705 shall be construed as exempting or excluding the owners and operators, and the designated representative, of a TR SO 2 Group 2

source or TR SO 2 Group 2 unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act. **§ 97.707 Computation of time.** (a) Unless otherwise stated, any time period scheduled, under the TR SO 2 Group 2 Trading Program, to begin on
the occurrence of an act or event shall begin on the day the act or event occurs.

(b) Unless otherwise stated, any time period scheduled, under the TR SO 2 Group 2 Trading Program, to begin
before the occurrence of an act or event shall be computed so that the period ends the day before the act or event

occurs.

(c) Unless otherwise stated, if the final day of any time period, under the TR

SO 2 Group 2 Trading Program, falls on a weekend or a State or Federal holiday, the time period shall be extended to the next business day.

**§ 97.708 Administrative appeal procedures.** 

The administrative appeal procedures
for decisions of the Administrator under
the TR SO 2 Group 2 Trading Program are set forth in part 78 of this chapter.

**§ 97.709 [Reserved]**

**§ 97.710 State SO** 2 **Group 2 trading budgets, new-unit set-asides, and variability** 
**limits.**

(a) The State SO 2 Group 2 trading budgets and new-unit set-asides for
allocations of TR SO 2 Group 2 allowances for the control periods in
2012 and thereafter are as follows:

State SO 2 group 2 trading budget (tons) * New-unit set-aside

(tons)

For 2012 and

thereafter For 2012 and thereafter

Alabama ........................................................................................................................ ................................... 161,871 4,856
Connecticut .................................................................................................................... .................................. 3,059 92
Delaware ....................................................................................................................... ................................... 7,784 234
District of Columbia ........................................................................................................... .............................. 337 10
Florida ........................................................................................................................ ...................................... 161,739 4,852
Kansas ......................................................................................................................... .................................... 57,275 1,718
Louisiana ...................................................................................................................... .................................... 90,477 2,714 Maryland ....................................................................................................................... ................................... 39,665 1,190
Massachusetts .................................................................................................................. ............................... 7,902 237
Minnesota ...................................................................................................................... .................................. 47,101 1,413
Nebraska ....................................................................................................................... ................................... 71,598 2,148 New Jersey ..................................................................................................................... ................................. 11,291 339
South Carolina ................................................................................................................. ................................ 116,483 3,494

Total .......................................................................................................................... ................................ 776,582 23,297

* Without variability limits.

(b) The States’ one-year and three-year variability limits for the State SO 2 Group 2 trading budgets for the control periods in 2014 and thereafter are as

follows:


### 45450 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

State One-year variability

limits Three-year variability

limits

2014 and thereafter (tons) 2016 and thereafter

(tons)

Alabama ........................................................................................................................ ................................... 16,187 9,346
Connecticut .................................................................................................................... .................................. 1,700 981
Delaware ....................................................................................................................... ................................... 1,700 981
District of Columbia ........................................................................................................... .............................. 1,700 981
Florida ........................................................................................................................ ...................................... 16,174 9,338
Kansas ......................................................................................................................... .................................... 5,728 3,307
Louisiana ...................................................................................................................... .................................... 9,048 5,224 Maryland ....................................................................................................................... ................................... 3,967 2,290
Massachusetts .................................................................................................................. ............................... 1,700 981
Minnesota ...................................................................................................................... .................................. 4,710 2,719
Nebraska ....................................................................................................................... ................................... 7,160 4,134 New Jersey ..................................................................................................................... ................................. 1,700 981
South Carolina ................................................................................................................. ................................ 11,648 6,725

**§ 97.711 Timing requirements for TR SO** 2 **Group 2 allowance allocations.**

(a) Existing units. (1) TR SO 2 Group 2 allowances are allocated, for the control periods in 2012 and each year thereafter, as set forth in appendix A to this subpart. Listing a unit in such appendix does not constitute a
determination that the unit is a TR SO 2 Group 2 unit, and not listing a unit in such appendix does not constitute a
determination that the unit is not a TR

SO 2 Group 2 unit.

(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being
allocated TR SO 2 Group 2 allowances does not operate, starting after 2011, during the control period in three consecutive years, such unit will not be
allocated the TR SO 2 Group 2 allowances set forth in appendix A to this subpart for the unit for the control periods in the seventh year after the first such year and in each year after that seventh year. All TR SO 2 Group 2
allowances that would otherwise have
been allocated to such unit will be
allocated to the new unit set-aside for the respective years involved. If such unit resumes operation, the
Administrator will allocate TR SO 2 Group 2 allowances to the unit in accordance with paragraph (b) of this

section.

(b) New units. (1) By July 1, 2012, and July 1 of each year thereafter, the
Administrator will calculate the TR SO 2 Group 2 allowance allocation for each

TR SO 2 Group 2 unit, in accordance with § 97.712, for the control period in the year of the applicable calculation deadline under this paragraph and will promulgate a notice of availability of the
results of the calculations.

(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced
in such notice.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations are in accordance with § 97.712 and §§ 97.706(b)(2) and 97.730 through

97.735.

(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By September 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(c) Units that are not TR SO 2 Group

2 units. For each control period in 2012 and thereafter, if the Administrator
determines that TR SO 2 Group 2
allowances were allocated under paragraph (a) of this section for the control period to a recipient that is not actually a TR SO 2 Group 2 unit under § 97.704 as of January 1, 2012, or whose deadline for meeting monitor certification requirements under § 97.730(b)(1) and (2) is after January 1, 2012, or if the Administrator determines
that TR SO 2 Group 2 allowances were allocated under paragraph (b) of this section and § 97.712 for the control period to a recipient that is not actually

a TR SO 2 Group 2 unit under § 97.704 as of January 1 of the control period, then the Administrator will notify the designated representative and will act in accordance with the following procedures:

(1) Except as provided in paragraph (c)(2) or (3) of this section, the Administrator will not record such TR

SO 2 Group 2 allowances under § 97.721.

(2) If the Administrator already

recorded such TR SO 2 Group 2 allowances under § 97.721 and if the

Administrator makes such determination before making deductions

for the source that includes such recipient under § 97.724(b) for such control period, then the Administrator

will deduct from the account in which

such TR SO 2 Group 2 allowances were

recorded an amount of TR SO 2 Group 2
allowances allocated for the same or a prior control period equal to the amount of such already recorded TR SO 2 Group
2 allowances. The authorized account representative shall ensure that there are

sufficient TR SO 2 Group 2 allowances in such account for completion of the

deduction.

(3) If the Administrator already
recorded such TR SO 2 Group 2 allowances under § 97.721 and if the
Administrator makes such determination after making deductions
for the source that includes such recipient under § 97.724(b) for such control period, then the Administrator will not make any deduction to take account of such already recorded TR

SO 2 Group 2 allowances.

(4) The Administrator will transfer the

TR SO 2 Group 2 allowances that are not recorded, or that are deducted, in accordance with paragraphs (c)(1) and(2) of this section to the new unit setaside, for the State in which such recipient is located, for the control period in the year of such transfer if the notice required in paragraph (b)(1) of this section for the control period in that year has not been promulgated or, such notice has been promulgated, in the
next year.


### 45451 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

**§ 97.712 TR SO** 2 **Group 2 allowance**
**allocations for new units.**

(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR SO 2 Group 2
allowances to TR SO 2 Group 2 units in a State that are not listed in appendix A to this subpart, to TR SO 2 Group 2
units that are so listed and whose
allocation of SO 2 Group 2 allowances for such control period is covered by § 97.711(c)(1) or (2), and to TR SO 2 Group 2 units that are so listed and, pursuant to § 97.711(a)(2), are not
allocated TR SO 2 Group 2 allowances for such control period but that operate during the immediately preceding control period:

(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be
allocated TR SO 2 Group 2 allowances in an amount equal to the applicable
amount of tons of SO 2 emissions as setforth in § 97.710(a). Each new unit setaside will be allocated additional TR

SO 2 Group 2 allowances in accordance with § 97.711(a)(2) and (c)(4).

(2) The designated representative of
such TR SO 2 Group 2 unit may submit to the Administrator a request, in a format prescribed by the Administrator,
to be allocated TR SO 2 Group 2 allowances for a control period, starting with the later of the control period in 2012, the first control period after the control period in which the TR SO 2 Group 2 unit commences commercial operation (for a unit not listed in appendix A to this subpart), or the first control period after the control period in which the unit resumes operation (for a unit listed in appendix A of this subpart) and for each subsequent control period.

(i) The request must be submitted on or before May 1 of the first control period for which TR SO 2 Group 2 allowances are sought and after the date
on which the TR SO 2 Group 2 unit commences commercial operation (for a unit not listed in appendix A of this subpart) or on which the unit resumes operation (for a unit listed in appendix A of this subpart).

(ii) For each control period for which an allocation is sought, the request must
be for TR SO 2 Group 2 allowances in an amount equal to the unit’s total tons of

SO 2 emissions during the immediately preceding control period.

(3) The Administrator will review
each TR SO 2 Group 2 allowance allocation request under paragraph (a)(2) of this section and will accept the request only if it meets the requirements of paragraph (a)(2) of this section. The Administrator will allocate TR SO 2 Group 2 allowances for each control period pursuant to an accepted request
as follows:

(i) After May 1 of such control period,
the Administrator will determine the
sum of the TR SO 2 Group 2 allowances requested in all accepted allowance allocation requests for such control period.

(ii) If the amount of TR SO 2 Group 2
allowances in the new unit set-aside for such control period is greater than or equal to the sum under paragraph (a)(3)(i) of this section, then the
Administrator will allocate the amount
of TR SO 2 Group 2 allowances requested
to each TR SO 2 Group 2 unit covered by an accepted allowance allocation request.

(iii) If the amount of TR SO 2 Group 2
allowances in the new unit set-aside for such control period is less than the sum under paragraph (a)(3)(i) of this section,
then the Administrator will allocate to
each TR SO 2 Group 2 unit covered by an accepted allowance allocation request the amount of the TR SO 2 Group 2 allowances requested, multiplied by
the amount of TR SO 2 Group 2
allowances in the new unit set-aside for such control period, divided by the sum determined under paragraph (a)(3)(i) of this section, and rounded to the nearest
allowance.

(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.711(b), each designated representative that submitted an allowance allocation request of the
amount of TR SO 2 Group 2 allowances (if any) allocated for such control period
to the TR SO 2 Group 2 unit covered by the request.

(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any
unallocated TR SO 2 Group 2 allowances
remain in the new unit set-aside under paragraph (a) of this section for a State for such control period, the
Administrator will allocate to each TR

SO 2 Group 2 unit that is in the State, is listed in appendix A to this subpart, and
continues to be allocated TR SO 2 Group 2 allowances for such control period in accordance with § 97.711(a)(2), an
amount of TR SO 2 Group 2 allowances equal to the following: The total amount of such remaining unallocated TR SO 2 Group 2 allowances in such new unit set-aside, multiplied by the unit’s allocation under § 97.711(a) for such control period, divided by the
remainder of the amount of tons in the applicable State SO 2 Group 2 trading budget minus the amount of tons in such new unit set-aside, and rounded to
the nearest allowance.

**§ 97.713 Authorization of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.715,
each TR SO 2 Group 2 source, including
all TR SO 2 Group 2 units at the source, shall have one and only one designated representative, with regard to all matters
under the TR SO 2 Group 2 Trading Program.

(1) The designated representative shall be selected by an agreement binding on the owners and operators of
the source and all TR SO 2 Group 2 units
at the source and shall act in accordance
with the certification statement in § 97.716(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.716:

(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source
and each TR SO 2 Group 2 unit at the source in all matters pertaining to the

TR SO 2 Group 2 Trading Program, notwithstanding any agreement between the designated representative and such owners and operators; and

(ii) The owners and operators of the
source and each TR SO 2 Group 2 unit at the source shall be bound by any
decision or order issued to the designated representative by the Administrator regarding the source or any such unit.

(b) Except as provided under § 97.715,
each TR SO 2 Group 2 source may have one and only one alternate designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.

(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR SO 2 Group 2 units at the source and shall act
in accordance with the certification statement in § 97.716(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.716,

(i) The alternate designated representative shall be authorized;

(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action,


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inaction, or submission by the designated representative; and

(iii) The owners and operators of the
source and each TR SO 2 Group 2 unit at the source shall be bound by any
decision or order issued to the alternate designated representative by the Administrator regarding the source or any such unit.

(c) Except in this section, § 97.702, and §§ 97.714 through 97.718, whenever
the term ‘‘ designated representative ’’ is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.

**§ 97.714 Responsibilities of designated representative and alternate designated**  **representative.**

(a) Except as provided under § 97.718 concerning delegation of authority to make submissions, each submission
under the TR SO 2 Group 2 Trading Program shall be made, signed, and certified by the designated representative or alternate designated representative for each TR SO 2 Group 2
source and TR SO 2 Group 2 unit for
which the submission is made. Each
such submission shall include the following certification statement by the designated representative or alternate designated representative: ‘‘ I am authorized to make this submission on behalf of the owners and operators of
the source or units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the
statements and information submitted
in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(b) The Administrator will accept or
act on a submission made for a TR SO 2 Group 2 source or a TR SO 2 Group 2 unit only if the submission has been made, signed, and certified in accordance with paragraph (a) of this section and § 97.718.

**§ 97.715 Changing designated representative and alternate designated**  **representative; changes in owners and operators.** 

(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.716. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date
when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the TR SO 2 Group 2 source
and the TR SO 2 Group 2 units at the

source.

(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.716. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the
time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the TR SO 2 Group 2 source and the TR SO 2 Group
2 units at the source.

(c) Changes in owners and operators. (1) In the event an owner or operator of

a TR SO 2 Group 2 source or a TR SO 2 Group 2 unit is not included in the list of owners and operators in the certificate of representation under § 97.716, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the source or unit, and the decisions and orders of the Administrator, as if the owner or operator were included in such list.

(2) Within 30 days after any change in the owners and operators of a TR SO 2 Group 2 source or a TR SO 2 Group 2 unit, including the addition of a new owner or operator, the designated representative or any alternate designated representative shall submit a
revision to the certificate of representation under § 97.716 amending the list of owners and operators to include the change.

**§ 97.716 Certificate of representation.**

(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:

(1) Identification of the TR SO 2 Group 2 source, and each TR SO 2 Group 2 unit at the source, for which the certificate of representation is submitted, including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type, identification number and nameplate capacity (in MWe rounded to the nearest tenth) of each generator served by each such unit, and actual or projected date of commencement of commercial operation.

(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

(3) A list of the owners and operators
of the TR SO 2 Group 2 source and of
each TR SO 2 Group 2 unit at the source.

(4) The following certification statements by the designated representative and any alternate designated representative—

(i) ‘‘ I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR

SO 2 Group 2 unit at the source. ’’

(ii) ‘‘ I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR

SO 2 Group 2 Trading Program on behalf of the owners and operators of the
source and of each TR SO 2 Group 2 unit
at the source and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions and by any order issued to me by the Administrator regarding the

source or unit. ’’

(iii) ‘‘ Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR SO 2 Group 2 unit, or where a utility or industrial customer purchases power from a TR

SO 2 Group 2 unit under a life-of-theunit, firm power contractual arrangement, I certify that: I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of each TR

SO 2 Group 2 unit at the source; and TR

SO 2 Group 2 allowances and proceeds of transactions involving TR SO 2 Group
2 allowances will be deemed to be held or distributed in proportion to each holder’s legal, equitable, leasehold, or contractual reservation or entitlement, except that, if such multiple holders have expressly provided for a different
distribution of TR SO 2 Group 2 allowances by contract, TR SO 2 Group 2 allowances and proceeds of transactions involving TR SO 2 Group 2


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allowances will be deemed to be held or
distributed in accordance with the

contract. ’’

(5) The signature of the designated representative and any alternate designated representative and the dates signed.

(b) Unless otherwise required by the Administrator, documents of agreement
referred to in the certificate of representation shall not be submitted to
the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

**§ 97.717 Objections concerning designated representative and alternate**  **designated representative.**

(a) Once a complete certificate of representation under § 97.716 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.716 is received by the Administrator.

(b) Except as provided in § 97.715(a) or (b), no objection or other
communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator
under the TR SO 2 Group 2 Trading Program.

(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR

SO 2 Group 2 allowance transfers.

**§ 97.718 Delegation by designated representative and alternate designated**  **representative.**

(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(c) In order to delegate authority to
make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;

(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an

‘‘ agent ’’ );

(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and

(4) The following certification statements by such designated representative or alternate designated representative:

(i) ‘‘ I agree that any electronic
submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.718(d) shall be deemed to be an electronic submission by me. ’’

(ii) ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.718(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me
under 40 CFR 97.718 is terminated. ’’

.

(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(e) Any electronic submission covered by the certification in paragraph (c)(4)(i)
of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall
be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.

**§ 97.719 [Reserved]**

**§ 97.720 Establishment of Allowance Management System accounts.** 

(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.716, the
Administrator will establish a compliance account for the TR SO 2 Group 2 source for which the certificate of representation was submitted, unless the source already has a compliance account. The designated representative and any alternate designated representative of the source shall be the authorized account representative and
the alternate authorized account representative respectively of the compliance account.

(b) General accounts —(1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring TR

SO 2 Group 2 allowances, by submitting to the Administrator a complete application for a general account. Such application shall designate one and only one authorized account representative and may designate one and only one
alternate authorized account representative who may act on behalf of the authorized account representative.

(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR SO 2 Group 2 allowances held in the general account.

(B) The agreement by which the
alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act
in lieu of the authorized account representative.

(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:

(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;

(B) An identifying name for the general account;

(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to


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represent their ownership interest with respect to the TR SO 2 Group 2 allowances held in the general account;

(D) The following certification statement by the authorized account representative and any alternate authorized account representative: ‘‘ I certify that I was selected as the authorized account representative or the
alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR SO 2 Group 2 allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities
under the TR SO 2 Group 2 Trading Program on behalf of such persons and that each such person shall be fully bound by my representations, actions, inactions, or submissions and by any order or decision issued to me by the Administrator regarding the general

account. ’’

(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.

(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted
to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted and upon and after such receipt by the Administrator:

(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to TR

SO 2 Group 2 allowances held in the general account in all matters pertaining
to the TR SO 2 Group 2 Trading Program, notwithstanding any agreement between the authorized account representative and such person.

(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative. (C) Each person who has an ownership interest with respect to TR

SO 2 Group 2 allowances held in the general account shall be bound by any
order or decision issued to the authorized account representative or
alternate authorized account representative by the Administrator regarding the general account.

(ii) Except as provided in paragraph (b)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to TR

SO 2 Group 2 allowances held in the general account. Each such submission shall include the following certification statement by the authorized account representative or any alternate authorized account representative: ‘‘ I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the

TR SO 2 Group 2 allowances held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements
and information submitted in this
document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ’’

(iii) Except in this section, whenever
the term ‘‘ authorized account representative ’’ is used in this subpart,
the term shall be construed to include the authorized account representative or any alternate authorized account representative.

(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the TR SO 2 Group 2 allowances in the general account.

(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a general account shall be binding on the new
alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the

TR SO 2 Group 2 allowances in the general account.

(iii)(A) In the event a person having an ownership interest with respect to

TR SO 2 Group 2 allowances in the general account is not included in the list of such persons in the application for a general account, such person shall be deemed to be subject to and bound by the application for a general account, the representation, actions, inactions,
and submissions of the authorized account representative and any alternate authorized account representative of the account, and the decisions and orders of the Administrator, as if the person were
included in such list.

(B) Within 30 days after any change in the persons having an ownership interest with respect to SO 2 Group 2 allowances in the general account, including the addition of a new person, the authorized account representative or any alternate authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the

TR SO 2 Group 2 allowances in the general account to include the change.

(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (b)(1)
of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the
Administrator.

(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication
submitted to the Administrator concerning the authorization, or any


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representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the
Administrator under the TR SO 2 Group 2 Trading Program.

(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or
submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR

SO 2 Group 2 allowance transfers.

(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this subpart.

(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an
electronic submission to the Administrator provided for or required under this subpart.

(iii) In order to delegate authority to
make an electronic submission to the
Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or
alternate authorized account representative, as appropriate, must
submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any)
of such authorized account representative or alternate authorized account representative;

(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to

as an ‘‘ agent ’’ );

(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;

(D) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ I agree that any
electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is
made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.720(b)(5)(iv) shall be deemed to be an electronic submission by me. ’’ ; and

(E) The following certification statement by such authorized account representative or alternate authorized account representative: ‘‘ Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.720(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.720(b)(5) is terminated. ’’

.

(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or
alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or
alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of
this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.

(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR SO 2 Group 2 allowance transfer under § 97.722 for any TR SO 2 Group 2 allowances in the
account to one or more other Allowance Management System accounts.

(ii) If a general account has no TR SO 2 Group 2 allowance transfers to or from the account for a 12-month period or longer and does not contain any TR SO 2 Group 2 allowances, the Administrator may notify the authorized account representative for the account that the account will be closed 20 business days
after the notice is sent. The account will be closed after the 20-day period unless, before the end of the 20-day period, the Administrator receives a correctly
submitted TR SO 2 Group 2 allowance transfer under § 97.722 to the account or a statement submitted by the authorized account representative or alternate authorized account representative demonstrating to the satisfaction of the Administrator good cause as to why the
account should not be closed.

(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of
this section.

(d) Responsibilities of authorized account representative and alternate authorized account representative. After
the establishment of an Allowance Management System account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction
or transfer of TR SO 2 Group 2 allowances in the account, only if the submission has been made, signed, and certified in accordance with §§ 97.714(a) and 97.718 or paragraphs (b)(2)(ii) and (b)(5) of this section.

**§ 97.721 Recordation of TR SO** 2 **Group 2**

**allowance allocations.**

(a) By September 1, 2011, the
Administrator will record in each TR

SO 2 Group 2 source’s compliance
account the TR SO 2 Group 2 allowances
allocated for the TR SO 2 Group 2 units
at the source in accordance with §§ 97.711(a) for the control periods in 2012, 2013, and 2014.

(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will
record in each TR SO 2 Group 2 source’s compliance account the TR SO 2 Group
2 allowances allocated for the TR SO 2 Group 2 units at the source in accordance with § 97.711(a) for the control period in the third year after the year of the applicable recordation deadline under this paragraph.

(c) By September 1, 2012 and September 1 of each year thereafter, the
Administrator will record in each TR

SO 2 Group 2 source’s compliance
account the TR SO 2 Group 2 allowances
allocated for the TR SO 2 Group 2 units
at the source in accordance with § 97.712 for the control period in the year of the applicable recordation deadline under this paragraph.

(d) When recording the allocation of

TR SO 2 Group 2 allowances for a TR

SO 2 Group 2 unit in a compliance


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account, the Administrator will assign
each TR SO 2 Group 2 allowance a unique identification number that will include digits identifying the year of the control period for which the TR SO 2 Group 2 allowance is allocated.

**§ 97.722 Submission of TR SO** 2 **Group 2**

**allowance transfers.**

(a) An authorized account representative seeking recordation of a

TR SO 2 Group 2 allowance transfer shall
submit the transfer to the Administrator.

(b) A TR SO 2 Group 2 allowance transfer shall be correctly submitted if:

(1) The transfer includes the following elements, in a format prescribed by the
Administrator:

(i) The account numbers established by the Administrator for both the transferor and transferee accounts;

(ii) The serial number of each TR SO 2 Group 2 allowance that is in the
transferor account and is to be transferred; and

(iii) The name and signature of the authorized account representative of the transferor account and the date signed;
and

(2) When the Administrator attempts to record the transfer, the transferor
account includes each TR SO 2 Group 2 allowance identified by serial number in
the transfer.

**§ 97.723 Recordation of TR SO** 2 **Group 2**

**allowance transfers.**

(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR SO 2 Group 2 allowance transfer, the Administrator
will record a TR SO 2 Group 2 allowance transfer by moving each TR SO 2 Group
2 allowance from the transferor account to the transferee account as specified by the request, provided that the transfer is correctly submitted under § 97.722.

(b)(1) A TR SO 2 Group 2 allowance
transfer that is submitted for recordation
after the allowance transfer deadline for a control period and that includes any

TR SO 2 Group 2 allowances allocated for any control period before such
allowance transfer deadline will not be
recorded until after the Administrator completes the deductions under § 97.724 for the control period immediately before such allowance
transfer deadline.

(2) A TR SO 2 Group 2 allowance
transfer that is submitted for recordation after the deadline for holding TR SO 2 Group 2 allowances described in § 97.725(b)(5) and that includes any TR

SO 2 Group 2 allowances allocated for a control period before the year of such
deadline will not be recorded until after the Administrator completes the deductions under § 97.725 for the control period immediately before the year of such deadline.

(c) Where a TR SO 2 Group 2 allowance transfer is not correctly submitted under § 97.722, the
Administrator will not record such
transfer.

(d) Within 5 business days of
recordation of a TR SO 2 Group 2 allowance transfer under paragraphs (a) and (b) of the section, the Administrator will notify the authorized account representatives of both the transferor
and transferee accounts.

(e) Within 10 business days of receipt
of a TR SO 2 Group 2 allowance transfer that is not correctly submitted under § 97.722, the Administrator will notify the authorized account representatives of both accounts subject to the transfer
of:

(1) A decision not to record the transfer, and

(2) The reasons for such nonrecordation.

**§ 97.724 Compliance with TR SO** 2 **Group 2**

**emissions limitation.**

(a) Availability for deduction for compliance. TR SO 2 Group 2 allowances
are available to be deducted for compliance with a source’s TR SO 2 Group 2 emissions limitation for a control period in a given year only if the

TR SO 2 Group 2 allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in the source’s compliance account as of the allowance
transfer deadline for such control period.

(b) Deductions for compliance. After the recordation, in accordance with § 97.723, of TR SO 2 Group 2 allowance transfers submitted by the allowance transfer deadline for a control period,
the Administrator will deduct from the compliance account TR SO 2 Group 2 allowances available under paragraph (a) of this section in order to determine
whether the source meets the TR SO 2 Group 2 emissions limitation for such control period, as follows:

(1) Until the amount of TR SO 2 Group 2 allowances deducted equals the
number of tons of total SO 2 emissions
from all TR SO 2 Group 2 units at the source for such control period; or

(2) If there are insufficient TR SO 2 Group 2 allowances to complete the deductions in paragraph (b)(1) of this section, until no more TR SO 2 Group 2 allowances available under paragraph (a) of this section remain in the compliance account.

(c)(1) Identification of TR SO 2 Group 2 allowances by serial number. The authorized account representative for a source’s compliance account may request that specific TR SO 2 Group 2 allowances, identified by serial number, in the compliance account be deducted
for emissions or excess emissions for a control period in accordance with paragraph (b) or (d) of this section. In order to be complete, such request shall be submitted to the Administrator by
the allowance transfer deadline for such control period and include, in a format prescribed by the Administrator, the
identification of the TR SO 2 Group 2 source and the appropriate serial
numbers.

(2) First-in, first-out. The
Administrator will deduct TR SO 2 Group 2 allowances under paragraph (b) or (d) of this section from the source’s compliance account in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the case of
identification of an insufficient amount
of TR SO 2 Group 2 allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following order:

(i) Any TR SO 2 Group 2 allowances
that were allocated to the units at the
source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR SO 2 Group 2 allowances that were allocated to any unit and
transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in
which the TR SO 2 Group 2 source has excess emissions, the Administrator will deduct from the source’s compliance
account an amount of TR SO 2 Group 2 allowances, allocated for the control period in the immediately following year, equal to two times the number of
tons of the source’s excess emissions.

(e) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraphs (b) and (d) of this section.

**§ 97.725 Compliance with TR SO** 2 **Group 2 assurance provisions.** 

(a) Availability for deduction. TR SO 2 Group 2 allowances are available to be deducted for compliance with the TR

SO 2 Group 2 assurance provisions for a control period in a given year by an
owner of one or more TR SO 2 Group 2 units in a State only if the TR SO 2 Group 2 allowances:

(1) Were allocated for the control period in the year or a prior year; and

(2) Are held in a compliance account, designated by the owner in accordance with paragraph (b)(4)(ii) of this section,


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of one of the owner’s TR SO 2 Group 2
sources in the State as of the deadline established in paragraph (b)(5) of this

section.

(b) Deductions for compliance. The
Administrator will deduct TR SO 2 Group 2 allowances available under paragraph (a) of this section for compliance with the TR SO 2 Group 2 assurance provisions for a State for a control period in a given year in accordance with the following procedures:

(1) By June 1, 2015 and June 1 of each year thereafter, the Administrator will:

(i) Calculate, separately for each State,
the total amount of SO 2 emissions from
all TR SO 2 Group 2 units in the State during the control period in the year before the year of this calculation deadline and the amount, if any, by
which such total amount of NO X emissions exceeds the State assurance level as described in § 97.706(c)(2)(iii);
and

(ii) Promulgate a notice of availability
of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations
of the SO 2 emissions for each TR SO 2 Group 2 unit and of the amounts described in §§ 97.706(c)(2)(iii)(A) and (B) for each State.

(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of
this section.

(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each TR

SO 2 Group 2 unit and each State for the control period in the year involved are in accordance with § 97.706(c)(2)(iii) and §§ 97.706(b) and 97.730 through

97.735.

(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By August 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.

(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR SO 2 Group 2
sources with total SO 2 emissions exceeding the State assurance level for a control period, as described in § 97.706(c)(2)(iii): (i) By August 15 immediately after the promulgation of such notice, the designated representative of each TR

SO 2 Group 2 source in each such State shall submit a statement, in a format prescribed by the Administrator:

(A) Listing all the owners of each TR

SO 2 Group 2 unit at the source, explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of

‘‘ owner ’’ in § 97.702, and listing, separately for each unit, the percentage of the legal, equitable, leasehold, or
contractual reservation or entitlement for each such owner as of midnight of December 31 of the control period in the year involved; and

(B) For each TR SO 2 Group 2 unit at the source that operates during, but is
allocated no TR SO 2 Group 2 allowances for, the control period in the year involved, identifying whether the unit is a coal-fired boiler, simple combustion turbine, or combined cycle turbine cycle and providing the unit’s allowable SO 2 emission rate for such control period.

(ii) By September 15 immediately after the promulgation of such notice, the Administrator will calculate, for
each such State and each owner of one

or more TR SO 2 Group 2 units in the State and for the control period in the year involved, each owner’s share of the
total SO 2 emissions from all TR SO 2 Group 2 units in the State, each owner’s assurance level, and the amount (if any)
of TR SO 2 Group 2 allowances that each
owner must hold in accordance with the calculation formula in § 97.706(c)(2)(i) and will promulgate a notice of availability of the results of these
calculations.

(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability required in paragraph (b)(3)(ii) of this

section.

(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing
whether the calculations for each owner for the control period in the year
involved are consistent with the SO 2 emissions for the relevant TR SO 2 Group 2 units as set forth in the notice required in paragraph (b)(2)(ii) of this section, the
definitions of ‘‘ owner ’’

, ‘‘ owner’s
assurance level ’’ , and ‘‘ owner’s share ’’ in § 97.702, and the calculation formula in § 97.706(c)(2)(i) and shall not raise any issues about any data used in the notice of data availability required in paragraph (b)(2)(ii) of this section.

(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section. By November 15 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that
the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(3)(iii)(A)
of this section.

(4) By December 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:

(i) Each owner identified, in such notice, as owning one or more TR SO 2 Group 2 units in a State and as being required to hold TR SO 2 Group 2 allowances shall designate the compliance account of one of the
sources at which such unit or units are located to hold such required TR SO 2 Group 2 allowances;

(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.

(5)(i) As of midnight of December 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount
of TR SO 2 Group 2 allowances, available for deduction under paragraph (a) of this section, equal to the amount the owner is required to hold as calculated by the Administrator and referenced in
such notice.

(ii) Notwithstanding the allowanceholding deadline specified in paragraph (b)(5)(i) of this section, if December 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day
thereafter.

(6) After December 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.723, of TR SO 2 Group 2 allowance transfers submitted by midnight of such date, the Administrator will deduct from each compliance account designated in accordance with paragraph (b)(4)(ii) of this section, TR

SO 2 Group 2 allowances available under paragraph (a) of this section, as follows:

(i) Until the amount of TR SO 2 Group 2 allowances deducted equals the


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amount that the owner designating the compliance account is required to hold as calculated by the Administrator and referenced in the notice required in paragraph (b)(3)(iii)(B) of this section; or

(ii) If there are insufficient TR SO 2 Group 2 allowances to complete the deductions in paragraph (b)(6)(i) of this section, until no more TR SO 2 Group 2 allowances available under paragraph (a) of this section remain in the compliance account.

(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice,
the amount of TR SO 2 Group 2 allowances that each owner is required
to hold in accordance with § 97.706(c)(2)(i) for the control period in the year involved shall continue to be such amount as calculated by the
Administrator and referenced in such notice required in paragraph (b)(3)(iii)(B) of this section, except as
follows:

(i) If any such data are revised by the
Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal
under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice,
then the Administrator will use the data
as so revised to recalculate the amounts
of TR SO 2 Group 2 allowances that owners are required to hold in
accordance with the calculation formula in § 97.706(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that—

(A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and

(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section. (ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the
Administrator will use the data as so
revised to recalculate the amounts of TR

SO 2 Group 2 allowances that owners are required to hold in accordance with the calculation formula in § 97.706(c)(2)(i) for the control period in the year involved with regard to the State involved, provided that such litigation was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii)(B) of this section.

(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR SO 2 Group 2 allowances that an owner is required to hold for the control period in the year involved with regard to the State
involved—

(A) Where the amount of TR SO 2 Group 2 allowances that an owner is required to hold increases as a result of the use of all such revised data, the Administrator will establish a new,
reasonable deadline on which the owner
shall hold the additional amount of TR

SO 2 Group 2 allowances in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section. The owner’s failure to hold such additional amount, as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s failure to hold such additional amount, as required, as of the
new deadline shall be a violation of the
Clean Air Act. Each TR SO 2 Group 2
allowance that the owner fails to hold as required as of the new deadline, and each day in the control period in the year involved, shall be a separate
violation of the Clean Air Act. After such deadline, the Administrator will make the appropriate deductions from the compliance account.

(B) For an owner for which the
amount of TR SO 2 Group 2 allowances required to be held decreases as a result of the use of all such revised data, the Administrator will record, in the compliance account that the owner designated in accordance with paragraph (b)(4)(ii) of this section, an
amount of TR SO 2 Group 2 allowances equal to the amount of the decrease to the extent such amount was previously deducted from the compliance account under paragraph (b)(6) of this section (and has not already been restored to the compliance account) for the control period in the year involved. (C) Each TR SO 2 Group 2 allowance held and deducted under paragraph (b)(7)(iii)(A) of this section, or recorded under paragraph (b)(7)(iii)(B) of this section, as a result of recalculation of requirements under the TR SO 2 Group 2 assurance provisions for a control period in a given year must be a TR SO 2 Group 2 allowance allocated for a control period in the same or a prior

year.

(c)(1) Identification of TR SO 2 Group 2 allowances by serial number. The authorized account representative for each source’s compliance account designated in accordance with paragraph (b)(4)(ii) of this section may request that specific TR SO 2 Group 2 allowances, identified by serial number, in the compliance account be deducted in accordance with paragraph (b)(6) or (7) of this section. In order to be complete, such request shall be submitted to the Administrator by the allowance-holding deadline described in paragraph (b)(5) of this section and include, in a format prescribed by the Administrator, the identification of the compliance account and the appropriate
serial numbers.

(2) First-in, first-out. The
Administrator will deduct TR SO 2 Group 2 allowances under paragraphs (b)(6) and (7) of this section from each source’s compliance account designated under paragraph (b)(4)(ii) of this section in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the
case of identification of an insufficient
amount of TR SO 2 Group 2 allowances in such request, on a first-in, first-out (FIFO) accounting basis in the following
order:

(i) Any TR SO 2 Group 2 allowances
that were allocated to the units at the
source and not transferred out of the compliance account, in the order of recordation; and then

(ii) Any TR SO 2 Group 2 allowances that were allocated to any unit and
transferred to and recorded in the compliance account pursuant to this subpart, in the order of recordation.

(d) Recordation of deductions. The
Administrator will record in the appropriate compliance account all
deductions from such an account under paragraph (b) of this section.

**§ 97.726 Banking.**

(a) A TR SO 2 Group 2 allowance may
be banked for future use or transfer in a compliance account or a general account in accordance with paragraph (b) of this section.

(b) Any TR SO 2 Group 2 allowance that is held in a compliance account or a general account will remain in such


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account unless and until the TR SO 2 Group 2 allowance is deducted or transferred under § 97.711(c), § 97.723, § 97.724, § 97.725, 97.727, 97.728,
97.742, or 97.743.

**§ 97.727 Account error.**

The Administrator may, at his or her
sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.

**§ 97.728 Administrator’s action on**
**submissions.**

(a) The Administrator may review and conduct independent audits concerning any submission under the TR SO 2 Group 2 Trading Program and make appropriate adjustments of the
information in the submission.

(b) The Administrator may deduct TR

SO 2 Group 2 allowances from or transfer

TR SO 2 Group 2 allowances to a source’s compliance account based on the information in a submission, as adjusted under paragraph (a)(1) of this section, and record such deductions and
transfers.

**§ 97.729 [Reserved]**

**§ 97.730 General monitoring, recordkeeping, and reporting requirements.** 

The owners and operators, and to the extent applicable, the designated representative, of a TR SO 2 Group 2 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subparts F and G of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.702 and in § 72.2 of this chapter shall apply,
the terms ‘‘ affected unit, ’’ ‘‘ designated representative, ’’ and ‘‘ continuous emission monitoring system ’’ (or

‘‘ CEMS ’’ ) in part 75 of this chapter shall
be deemed to refer to the terms ‘‘ TR SO 2 Group 2 unit, ’’ ‘‘ designated representative, ’’ and ‘‘ continuous emission monitoring system ’’ (or

‘‘ CEMS ’’ ) respectively as defined in § 97.702, and the term ‘‘ newly affected

unit ’’ shall be deemed to mean ‘‘ newly
affected TR SO 2 Group 2 unit ’’ . The owner or operator of a unit that is not

a TR SO 2 Group 2 unit but that is monitored under § 75.16(b)(2) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a TR SO 2 Group 2 unit.

(a) Requirements for installation, certification, and data accounting. The owner or operator of each TR SO 2 Group
2 unit shall: (1) Install all monitoring systems required under this subpart for monitoring SO 2 mass emissions and individual unit heat input (including all systems required to monitor SO 2 concentration, stack gas moisture content, stack gas flow rate, CO 2 or O 2 concentration, and fuel flow rate, as applicable, in accordance with §§ 75.11 and 75.16 of this chapter);

(2) Successfully complete all certification tests required under § 97.731 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator shall meet the monitoring system certification and other requirements of paragraphs (a)(1) and (2) of this section on or before the following dates. The owner or operator shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.

(1) For the owner or operator of a TR

SO 2 Group 2 unit that commences commercial operation before July 1, 2011, by January 1, 2012.

(2) For the owner or operator of a TR

SO 2 Group 2 unit that commences commercial operation on or after July 1, 2011, by the later of the following dates:

(i) January 1, 2012; or (ii) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.

(3) For the owner or operator of a TR

SO 2 Group 2 unit for which
construction of a new stack or flue or
installation of add-on SO 2 emission controls is completed after the applicable deadline under paragraph (b)(1) or (2) of this section, by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on
which emissions first exit to the atmosphere through the new stack or
flue or add-on SO 2 emissions controls.

(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a TR opt-in application is
submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.741(c).

(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a TR SO 2 Group 2 opt-in unit, by the date on
which the TR SO 2 Group 2 opt-in unit enters the TR SO 2 Group 2 Trading Program as provided in § 97.741(h).

(c) Reporting data. The owner or operator of a TR SO 2 Group 2 unit that does not meet the applicable compliance date set forth in paragraph (b) of this section for any monitoring system under paragraph (a)(1) of this section shall, for each such monitoring system, determine, record, and report maximum potential (or, as appropriate, minimum potential) values for SO 2 concentration, stack gas flow rate, stack gas moisture content, fuel flow rate, and any other parameters required to
determine SO 2 mass emissions and heat input in accordance with § 75.31(b)(2) or (c)(3) of this chapter or section 2.4 of appendix D to part 75 of this chapter, as applicable.

(d) Prohibitions. (1) No owner or operator of a TR SO 2 Group 2 unit shall use any alternative monitoring system, alternative reference method, or any other alternative to any requirement of this subpart without having obtained prior written approval in accordance with § 97.735.

(2) No owner or operator of a TR SO 2 Group 2 unit shall operate the unit so as to discharge, or allow to be discharged, SO 2 emissions to the atmosphere without accounting for all
such emissions in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(3) No owner or operator of a TR SO 2 Group 2 unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording SO 2 mass emissions discharged into the atmosphere or heat input, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(4) No owner or operator of a TR SO 2 Group 2 unit shall retire or permanently
discontinue use of the continuous emission monitoring system, any component thereof, or any other approved monitoring system under this subpart, except under any one of the following circumstances:

(i) During the period that the unit is covered by an exemption under § 97.705 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the
Administrator for use at that unit that provides emission data for the same


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pollutant or parameter as the retired or discontinued monitoring system; or

(iii) The designated representative
submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.731(d)(3)(i).

(e) Long-term cold storage. The owner or operator of a TR SO 2 Group 2 unit is subject to the applicable provisions of § 75.4(d) of this chapter concerning units in long-term cold storage.

**§ 97.731 Initial monitoring system certification and recertification procedures.** 

(a) The owner or operator of a TR SO 2 Group 2 unit shall be exempt from the initial certification requirements of this section for a monitoring system under § 97.730(a)(1) if the following conditions

are met:

(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and

(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B and D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of
this section.

(b) The recertification provisions of this section shall apply to a monitoring system under § 97.730(a)(1) exempt from initial certification requirements under paragraph (a) of this section.

(c) [Reserved] (d) Except as provided in paragraph (a) of this section, the owner or operator
of a TR SO 2 Group 2 unit shall comply with the following initial certification and recertification procedures, for a continuous monitoring system ( i.e., a continuous emission monitoring system and an excepted monitoring system under appendix D to part 75 of this chapter) under § 97.730(a)(1). The owner or operator of a unit that qualifies to use the low mass emissions excepted monitoring methodology under § 75.19 of this chapter or that qualifies to use an alternative monitoring system under subpart E of part 75 of this chapter shall comply with the procedures in paragraph (e) or (f) of this section respectively.

(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under § 97.730(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.730(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.

(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.730(a)(1) that may significantly affect the ability of the system to accurately measure or
record SO 2 mass emissions or heat input rate or to meet the quality-assurance and quality-control requirements of § 75.21 of this chapter or appendix B to part 75 of this chapter, the owner or operator shall recertify the monitoring system in accordance with § 75.20(b) of this chapter. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit’s operation that may significantly change the stack flow or concentration profile, the owner or operator shall recertify each continuous emission monitoring system whose accuracy is potentially affected by the change, in accordance with § 75.20(b) of this chapter. Examples of changes to a continuous emission monitoring system that require recertification include: Replacement of the analyzer, complete replacement of an existing continuous emission monitoring system, or change in location or orientation of the sampling probe or site. Any fuel flowmeter system under § 97.730(a)(1) is subject to the recertification requirements in § 75.20(g)(6) of this chapter.

(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.730(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words

‘‘ certification ’’ and ‘‘ initial certification ’’ are replaced by the word

‘‘ recertification ’’ and the word ‘‘ certified ’’ is replaced by the word ‘‘ recertified ’’

.

(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office
and the Administrator written notice of the dates of certification testing, in accordance with § 97.733.

(ii) Certification application. The designated representative shall submit
to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.

(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under
the TR SO 2 Group 2 Trading Program for a period not to exceed 120 days after receipt by the Administrator of the complete certification application for the monitoring system under paragraph (d)(3)(ii) of this section. Data measured and recorded by the provisionally certified monitoring system, in accordance with the requirements of part 75 of this chapter, will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that
the Administrator does not invalidate the provisional certification by issuing a notice of disapproval within 120 days of the date of receipt of the complete certification application by the
Administrator.

(iv) Certification application approval

process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the
event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter
and is included in the certification application will be deemed certified for
use under the TR SO 2 Group 2 Trading Program.

(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter,
then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day review period specified in paragraph


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(d)(3) of this section shall not begin before receipt of a complete certification application.

(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).

(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of
a monitor in accordance with § 97.732(b).

(v) Procedures for loss of certification.
If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section,
then:

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved SO 2 pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of

SO 2 and the maximum potential flow rate, as defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO 2 concentration or the minimum potential O 2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter. (B) The designated representative
shall submit a notification of
certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this

section.

(C) The owner or operator shall repeat
all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days
after the date of issuance of the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the
certification and recertification requirements in § 75.20(g) of this chapter.

(f) The designated representative of
each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.

**§ 97.732 Monitoring system out-of-control periods.** 

(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or appendix D to part 75 of this chapter.

(b) Audit decertification. Whenever both an audit of a monitoring system
and a review of the initial certification or recertification application reveal that any monitoring system should not have
been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.731 or the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission and at the time of the audit, the
Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit
shall be either a field audit or an audit of any information submitted to the Administrator or any permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data
from the date of issuance of the
notification of the revoked certification
status until the date and time that the owner or operator completes subsequently approved initial
certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable
initial certification or recertification procedures in § 97.731 for each disapproved monitoring system.

**§ 97.733 Notifications concerning monitoring.** 

The designated representative of a TR

SO 2 Group 2 unit shall submit written
notice to the Administrator in accordance with § 75.61 of this chapter.

**§ 97.734 Recordkeeping and reporting.**

(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in this section, the applicable recordkeeping and reporting requirements in subparts F and G of part 75 of this chapter, and the requirements of § 97.714(a).

(b) Monitoring plans. The owner or operator of a TR SO 2 Group 2 unit shall comply with requirements of § 75.62 of this chapter.

(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all
initial certification or recertification tests required under § 97.731, including the information required under § 75.63 of this chapter.

(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:

(1) The designated representative shall report the SO 2 mass emissions data and heat input data for the TR SO 2 Group 2 unit, in an electronic quarterly report in a format prescribed by the Administrator, for each calendar quarter beginning with:

(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering January 1, 2012 through March 31, 2012;

(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.730(b), unless that quarter is the third or fourth quarter of 2011, in which case reporting shall


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commence in the quarter covering January 1, 2012 through March 31, 2012;

(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a TR opt-in application is
submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.741(c); and

(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a TR

SO 2 Group 2 opt-in unit, the calendar quarter corresponding to the date on
which the TR SO 2 Group 1 opt-in unit
enters the TR SO 2 Group 2 Trading Program as provided in § 97.71(h).

(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.

(3) For TR SO 2 Group 2 units that are also subject to the Acid Rain Program,

TR NO X Annual Trading Program, or TR

NO X Ozone Season Trading Program, quarterly reports shall include the applicable data and information required by subparts F through H of part 75 of this chapter as applicable, in
addition to the SO 2 mass emission data, heat input data, and other information required by this subpart.

(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.

(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any
corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction. (ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of
this section.

(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully
monitored. The certification shall state
that:

(1) The monitoring data submitted
were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and

(2) For a unit with add-on SO 2 emission controls and for all hours
where SO 2 data are substituted in accordance with § 75.34(a)(1) of this chapter, the add-on emission controls were operating within the range of parameters listed in the quality assurance/quality control program under appendix B to part 75 of this chapter and the substitute data values do not systematically underestimate SO 2 emissions.

**§ 97.735 Petitions for alternatives to monitoring, recordkeeping, or reporting**  **requirements.**

(a) The designated representative of a

TR SO 2 Group 2 unit may submit a petition under § 75.66 of this chapter to the Administrator, requesting approval to apply an alternative to any requirement of §§ 97.730 through 97.734 or paragraph (5)(i) or (ii) of the
definition of ‘‘ owner’s share ’’ in § 97.702.

(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition, including, at a minimum, the following information:

(i) Identification of each unit and source covered by the petition;

(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;

(iii) A description and diagram of any equipment and procedures used in the proposed alternative;

(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the
alternative will be de minimis; and

(v) Any other relevant information that the Administrator may require.

(c) Use of an alternative to any requirement referenced in paragraph (a)
of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.

**§ 97.740 General requirements for TR SO** 2 **Group 2 opt-in units.**

(a) A TR SO 2 Group 2 opt-in unit must
be a unit that:

(1) Is located in a State; (2) Is not a TR SO 2 Group 2 unit under § 97.704;

(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and

(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.

(b) A TR SO 2 Group 2 opt-in unit shall
be deemed to be a TR SO 2 Group 2 unit for purposes of applying this subpart, except for §§ 97.705, 97.711, and 97.712.

(c) Solely for purposes of applying the requirements of §§ 97.713 through 97.718 and §§ 97.730 through 97.735, a unit for which a TR opt-in application
is submitted and not withdrawn and is not yet approved or disapproved under § 97.742 shall be deemed to be a TR SO 2 Group 2 unit.

(d) Any TR SO 2 Group 2 opt-in unit, and any unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved under § 97.742, located at
the same source as one or more TR SO 2 Group 2 units shall have the same designated representative and alternate designated representative as such TR

SO 2 Group 2 units.

**§ 97.741 Opt-in process.**

A unit meeting the requirements for a

TR SO 2 Group 2 opt-in unit in § 97.740(a) may become a TR SO 2 Group 2 opt-in unit only if, in accordance with this section, the designated representative of the unit submits a complete TR opt-in application for the unit and the Administrator approves the application.

(a) Applying to opt-in. The designated representative of the unit may submit a complete TR opt-in application for the unit at any time, except as provided under § 97.742(e). A complete TR opt-in application shall include the following elements in a format prescribed by the
Administrator:

(1) Identification of the unit and the source where the unit is located,


### 45463 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules

including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, and unit identification number and type;

(2) A certification that the unit: (i) Is not a TR SO 2 Group 2 unit under § 97.704;

(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;

(iii) Vents all of its emissions to a stack; and

(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;

(3) A monitoring plan in accordance with §§ 97.730 through 97.735;

(4) A statement that the unit, if approved to become a TR SO 2 Group 2 unit under paragraph (g) of this section, may withdraw from the TR SO 2 Group 2 Trading Program only in accordance with § 97.742;

(5) A statement that the unit, if approved to become a TR SO 2 Group 2 unit under paragraph (g) of this section, is subject to, and the owners and operators of the unit must comply with, the requirements of § 97.743;

(6) A complete certificate of representation under § 97.716 consistent with § 97.740, if no designated representative has been previously designated for the source that includes the unit; and

(7) The signature of the designated representative and the date signed.

(b) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan submitted under paragraph (a)(3) of this section. The monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the SO 2 emission rate and heat input of the unit and all other applicable parameters are monitored and reported in accordance with §§ 97.730 through 97.735. A determination of sufficiency shall not be construed as acceptance or approval of the monitoring plan.

(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the monitoring plan is sufficient under paragraph (b) of this section, the owner or operator of the unit shall monitor and report the SO 2 emission rate and the heat input of the unit and all other applicable parameters, in accordance with §§ 97.730 through 97.735, starting
on the date of certification of the necessary monitoring systems under §§ 97.730 through 97.735 and continuing until the TR opt-in application submitted under paragraph (a) of this section is disapproved under this section or, if such TR opt-in application is approved, the date and
time when the unit is withdrawn from
the TR SO 2 Group 2 Trading Program in accordance with § 97.742.

(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which
the unit enters the TR SO 2 Group 2 Trading Program under paragraph (h) of this section, during which period monitoring system availability must not be less than 98 percent under §§ 97.730 through 97.735 and the unit must be in full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.

(2) To the extent the SO 2 emission rate and the heat input of the unit are monitored and reported in accordance with §§ 97.730 through 97.735 for one or more entire control periods, in addition to the control period under paragraph (c)(1)(ii) of this section, during which control periods monitoring system availability is not less than 98 percent under §§ 97.730 through 97.735 and the unit is in full compliance with any applicable State or Federal emissions or emissions-related requirements and which control periods begin not more than 3 years before the unit enters the

TR SO 2 Group 2 Trading Program under paragraph (h) of this section, such information shall be used as provided in paragraphs (e) and (f) of this section.

(d) Statement on compliance. After submitting to the Administrator all quarterly reports required for the unit under paragraph (c) of this section, the designated representative shall submit, in a format prescribed by the Administrator, to the Administrator a statement that, for the years covered by such quarterly reports, the unit was in full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.

(e) Baseline heat input. The unit’s baseline heat input shall equal:

(1) If the unit’s SO 2 emission rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s total heat input (in mmBtu) for such control period; or

(2) If the unit’s SO 2 emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, the average of the amounts of the unit’s total heat input (in mmBtu) for such control periods. (f) Baseline SO 2 emission rate. The
unit’s baseline SO 2 emission rate shall equal:

(1) If the unit’s SO 2 emission rate and heat input are monitored and reported for only one entire control period, in accordance with paragraph (c) of this section, the unit’s SO 2 emission rate (in lb/mmBtu) for such control period;

(2) If the unit’s SO 2 emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of thissection, and the unit does not have addon SO 2 emission controls during any such control periods, the average of the
amounts of the unit’s SO 2 emission rate (in lb/mmBtu) for such control periods;

or (3) If the unit’s SO 2 emission rate and heat input are monitored and reported for more than one entire control period, in accordance with paragraph (c) of this section, and the unit has add-on SO 2 emission controls during any such control periods, the average of the
amounts of the unit’s SO 2 emission rate (in lb/mmBtu) for such control periods during which the unit has add-on SO 2 emission controls.

(g) Review of TR opt-in application. (1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the
Administrator determines that the designated representative shows that the unit meets the requirements for a TR

SO 2 Group 2 opt-in unit in § 97.640, the element certified in paragraph (a)(2)(iv) of this section, and the monitoring and reporting requirements of paragraph (c) of this section, the Administrator willissue a written approval of the TR optin application for the unit. The written approval will state the unit’s baseline heat input and baseline SO 2 emission
rate. The Administrator will thereafter establish a compliance account for the
source that includes the unit unless the source already has a compliance

account.

(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines
that the unit cannot meet the requirements for a TR SO 2 Group 2 optin unit in § 97.740, the element certified in paragraph (a)(2)(iv) of this section, or the monitoring and reporting requirements in paragraph (c) of this section, the Administrator will issue a written disapproval of the TR opt-in application for the unit.

(h) Date of entry into TR SO 2 Group 2 Trading Program. A unit for which a


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TR opt-in application is approved under paragraph (g)(1) of this section shall
become a TR SO 2 Group 2 opt-in unit,
and a TR SO 2 Group 2 unit, effective as of the later of January 1, 2012 or January 1 of the first control period during which such approval is issued.

**§ 97.742 Withdrawal of TR SO** 2 **Group 2 opt-in unit from TR SO**  2 **Group 2 Trading Program.** 

A TR SO 2 Group 2 opt-in unit may
withdraw from the TR SO 2 Group 2 Trading Program only if, in accordance with this section, the designated representative of the unit submits a request to withdraw the unit and the Administrator issues a written approval of the request.

(a) Requesting withdrawal. In order to
withdraw the TR SO 2 Group 2 opt-in
unit from the TR SO 2 Group 2 Trading Program, the designated representative
of the unit shall submit to the Administrator a request to withdraw the unit effective as of midnight of December 31 of a specified calendar year, which date must be at least 4 years after December 31 of the year of the unit’s entry into the TR SO 2 Group 2 Trading Program under § 97.741(h). The request shall be in a format prescribed by the Administrator and shall be submitted no later than 90 days before the requested effective date of
withdrawal.

(b) Conditions for withdrawal. Before

a TR SO 2 Group 2 opt-in unit covered by the request to withdraw may
withdraw from the TR SO 2 Group 2 Trading Program, the following
conditions must be met:

(1) For the control period ending on
the date on which the withdrawal is to be effective, the source that includes the

TR SO 2 Group 2 opt-in unit must meet the requirement to hold TR SO 2 Group 2 allowances under §§ 97.724 and 97.725 and cannot have any excess

emissions.

(2) After the requirement under paragraph (b)(1) of this section is met,
the Administrator will deduct from the compliance account of the source that
includes the TR SO 2 Group 2 opt-in unit

TR SO 2 Group 2 allowances equal in
amount to and allocated for the same or a prior control period as any TR SO 2 Group 2 allowances allocated to the TR

SO 2 Group 2 opt-in unit under § 97.744 for any control period after the date on
which the withdrawal is to be effective.
If there are no other TR SO 2 Group 2 units at the source, the Administrator will close the compliance account, and the owners and operators of the TR SO 2 Group 2 opt-in unit may submit a TR

SO 2 Group 2 allowance transfer for any remaining TR SO 2 Group 2 allowances to another Allowance Management System account in accordance with §§ 97.722 and 97.723.

(c) Approving withdrawal. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full
amount of TR SO 2 Group 2 allowances required), the Administrator will issue a written approval of the request to withdraw, which will become effective as of midnight on December 31 of the calendar year for which the withdrawal was requested. The unit covered by the request shall continue to be a TR SO 2 Group 2 opt-in unit until the effective date of the withdrawal and shall comply with all requirements under the TR SO 2 Group 2 Trading Program concerning any control periods for which the unit

is a TR SO 2 Group 2 opt-in unit, even if such requirements arise or must be complied with after the withdrawal
takes effect.

(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR

SO 2 Group 2 opt-in unit.

(d) Reapplication upon failure to meet conditions of withdrawal. If the Administrator disapproves the request to withdraw, the designated representative of the unit may submit another request to withdraw in accordance with paragraphs (a) and (b)
of this section.

(e) Ability to reapply to the TR SO 2 Group 2 Trading Program. Once a TR

SO 2 Group 2 opt-in unit withdraws from
the TR SO 2 Group 2 Trading Program, the designated representative may not submit another opt-in application under § 97.741 for such unit before the date that is 4 years after the date on which
the withdrawal became effective.

**§ 97.743 Change in regulatory status.**

(a) Notification. If a TR SO 2 Group 2 opt-in unit becomes a TR SO 2 Group 2 unit under § 97.704, then the designated representative of the unit shall notify the Administrator in writing of such change in the TR SO 2 Group 2 opt-in unit’s regulatory status, within 30 days of such change.

(b) Administrator’s actions. (1) If a TR

SO 2 Group 2 opt-in unit becomes a TR

SO 2 Group 2 unit under § 97.604, the Administrator will deduct, from the compliance account of the source that
includes the TR SO 2 Group 2 opt-in unit
that becomes a TR SO 2 Group 2 unit under § 97.704, TR SO 2 Group 2 allowances equal in amount to and allocated for the same or a prior control period as: (i) Any TR SO 2 Group 2 allowances
allocated to the TR SO 2 Group 2 opt-in unit under § 97.744 for any control period starting after the date on which
the TR SO 2 Group 2 opt-in unit becomes

a TR SO 2 Group 2 unit under § 97.704;
and

(ii) If the date on which the TR SO 2 Group 2 opt-in unit becomes a TR SO 2 Group 2 unit under § 97.704 is not December 31, the TR SO 2 Group 2
allowances allocated to the TR SO 2 Group 2 opt-in unit under § 97.744 for the control period that includes the date
on which the TR SO 2 Group 2 opt-in
unit becomes a TR SO 2 Group 2 unit under § 97.704—

(A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

SO 2 Group 2 opt-in unit becomes a TR

SO 2 Group 2 unit under § 97.704, divided by the total number of days in the control period, and

(B) Rounded to the nearest allowance.
(2) The designated representative shall ensure that the compliance
account of the source that includes the

TR SO 2 Group 2 opt-in unit that
becomes a TR SO 2 Group 2 unit under § 97.704 contains the TR SO 2 Group 2 allowances necessary for completion of the deduction under paragraph (b)(1) of
this section.

(3)(i) For control periods starting after
the date on which the TR SO 2 Group 2 opt-in unit becomes a TR SO 2 Group 2 unit under § 97.704, the TR SO 2 Group 2 opt-in unit will be allocated TR SO 2 Group 2 allowances in accordance with § 97.712.

(ii) If the date on which the TR SO 2 Group 2 opt-in unit becomes a TR SO 2 Group 2 unit under § 97.704 is not December 31, the following amount of

TR SO 2 Group 2 allowances will be
allocated to the TR SO 2 Group 2 opt-in unit (as a TR SO 2 Group 2 unit) in accordance with § 97.712 for the control period that includes the date on which
the TR SO 2 Group 2 opt-in unit becomes

a TR SO 2 Group 2 unit under § 97.704:

(A) The amount of TR SO 2 Group 2
allowances otherwise allocated to the

TR SO 2 Group 2 opt-in unit (as a TR SO 2 Group 2 unit) in accordance with § 97.712 for the control period;

(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR

SO 2 Group 2 opt-in unit becomes a TR

SO 2 Group 2 unit under § 97.704, divided by the total number of days in the control period; and

(C) Rounded to the nearest allowance.


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**§ 97.744 TR SO** 2 **Group 2 allowance**
**allocations to TR SO** 2 **Group 2 opt-in units.**

(a) Timing requirements. (1) When the TR opt-in application is approved for a unit under § 97.741(g), the
Administrator will issue TR SO 2 Group
2 allowances and allocate them to the unit for the control period in which the
unit enters the TR SO 2 Group 2 Trading Program under § 97.741(h), in accordance with paragraph (b) of this

section.

(2) By no later than October 31 of the control period after the control period in
which a TR SO 2 Group 2 opt-in unit
enters the TR SO 2 Group 2 Trading Program under § 97.741(h) and October 31 of each year thereafter, the
Administrator will issue TR SO 2 Group
2 allowances and allocate them to the

TR SO 2 Group 2 opt-in unit for the control period that includes such
allocation deadline and in which the

unit is a TR SO 2 Group 2 opt-in unit, in accordance with paragraph (b) of this

section.

(b) Calculation of allocation. For each control period for which a TR SO 2 Group 2 opt-in unit is to be allocated TR

SO 2 Group 2 allowances, the
Administrator will issue and allocate TR SO 2 Group 2 allowances in accordance with the following procedures:

(1) The heat input (in mmBtu) used for calculating the TR SO 2 Group 2
allowance allocation will be the lesser
of:

(i) The TR SO 2 Group 2 opt-in unit’s baseline heat input determined under § 97.741(g); or

(ii) The TR SO 2 Group 2 opt-in unit’s heat input, as determined in accordance with §§ 97.730 through 97.735, for the immediately prior control period, except when the allocation is being calculated for the control period in
which the TR SO 2 Group 2 opt-in unit
enters the TR SO 2 Group 2 Trading Program under § 97.741(h).

(2) The SO 2 emission rate (in lb/ mmBtu) used for calculating TR SO 2 Group 2 allowance allocations will be
the lesser of:

(i) The TR SO 2 Group 2 opt-in unit’s
baseline SO 2 emission rate (in lb/ mmBtu) determined under § 97.741(g) and multiplied by 70 percent; or

(ii) The most stringent State or
Federal SO 2 emissions limitation applicable to the TR SO 2 Group 2 optin unit at any time during the control period for which TR SO 2 Group 2
allowances are to be allocated. (3) The Administrator will issue TR

SO 2 Group 2 allowances and allocate
them to the TR SO 2 Group 2 opt-in unit in an amount equaling the heat input under paragraph (b)(1) of this section, multiplied by the SO 2 emission rate under paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded to
the nearest allowance.

(c) Recordation. (1) The Administrator will record, in the compliance account
of the source that includes the TR SO 2 Group 2 opt-in unit, the TR SO 2 Group
2 allowances allocated to the TR SO 2 Group 2 opt-in unit under paragraph (a)(1) of this section.

(2) By December 1 of the control period after the control period in which

a TR SO 2 Group 2 opt-in unit enters the

TR SO 2 Group 2 Trading Program under § 97.741(h) and December 1 of each year thereafter, the Administrator will record, in the compliance account of the
source that includes the TR SO 2 Group 2 opt-in unit, the TR SO 2 Group 2
allowances allocated to the TR SO 2 Group 2 opt-in unit under paragraph (a)(2) of this section.

[FR Doc. 2010–17007 Filed 7–30–10; 8:45 am]

**BILLING CODE 6560–50–P**