1

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

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

[EPA-HQ-OAR-2009-0491; FRL-xxxx-x]

RIN 2060-AP50

Federal Implementation Plans to Reduce Interstate Transport of 

Fine Particulate Matter and Ozone

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: EPA is proposing to limit the interstate transport of 

emissions of nitrogen oxides (NOX) and sulfur dioxide (SO2). 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 (PM2.5) 

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 PM2.5 NAAQS by 2014 or earlier. To the extent 
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the proposed FIPs do not fully address all significant 

transport, EPA is committed to assuring that any additional 

reductions needed are addressed quickly.

DATES: Comments. Comments must be received on or before

[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER]. 

Public Hearing: Public hearings will be held on [ADD THE 

THREE DATES; MAKE SURE A FEW DAYS APART FOR EACH] in [ADD THE 

THREE LOCATIONS]. Please refer to SUPPLEMENTARY INFORMATION for 

additional information on the comment period and the public 

hearing.

ADDRESSES: Submit your comments, identified by Docket ID No. 

EPA-HQ-OAR-2009-0491 by one of the following methods:

 www.regulations.gov. Follow the online instructions for 

submitting comments. Attention Docket ID No. EPA-HQ-OAR2009-0491.

 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-OAR2009-0491.

 Mail: EPA Docket Center, EPA West (Air Docket), Attention

Docket ID No. EPA-HQ-OAR-2009-0491, U.S. Environmental 

Protection Agency, Mailcode: 2822T, 1200 Pennsylvania 

Avenue, NW, Washington, DC 20460. Please include 2 copies. 
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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-OAR2009-0491. EPA's policy is that all comments received will be 

included in the public docket without change and may be made 

available online at www.regulations.gov, including any personal 

information provided, unless the comment includes information 

claimed to be Confidential Business Information (CBI) or other 

information whose disclosure is restricted by statute. Do not 

submit information that you consider to be CBI or otherwise 

protected through www.regulations.gov or e-mail. The 

www.regulations.gov Website is an "anonymous access" system, 

which means EPA will not know your identity or contact 

information unless you provide it in the body of your comment. 
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If you send an e-mail comment directly to EPA without going 

through www.regulations.gov, your e-mail address will be 

automatically captured and included as part of the comment that 

is placed in the public docket and made available on the 

Internet. If you submit an electronic comment, EPA recommends 

that you include your name and other contact information in the

body of your comment and with any disk or CD-ROM you submit. If 

EPA cannot read your comment due to technical difficulties and 

cannot contact you for clarification, EPA may not be able to 

consider your comment. Electronic files should avoid the use of 

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 

www.epa.gov/epahome/dockets.htm. 

Docket. All documents in the docket are listed in the 

www.regulations.gov index. Although listed in the index, some 

information is not publicly available, e.g., CBI or other 

information whose 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 

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 
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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. [NEEDS TO BE UPDATED]

CAA or Act Clean Air Act

CAIR Clean Air Interstate Rule

CBI Confidential Business Information

EGU Electric Generating Unit

FGD Flue Gas Desulfurization

FIP Federal Implementation Plan

EPA U.S. Environmental Protection Agency

IPM Integrated Planning Model

lb/mmbtu Pounds Per Million British Thermal Unit 

μg/m3 Micrograms Per Cubic Meter

NAAQS National Ambient Air Quality Standards

NOx Nitrogen Oxides

SNCR Selective Non-catalytic Reduction
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SCR Selective Catalytic Reduction

SIP State Implementation Plan

PM2.5 Fine Particulate Matter, Less Than 2.5 

Micrometers

PM10 Fine and Coarse Particulate Matter, Less than 10 

Micrometers

PM Particulate Matter

RIA Regulatory Impact Analysis

SO2 Sulfur Dioxide

SOX Sulfur Oxides, Including Sulfur Dioxide (SO2) and 

Sulfur Trioxide (SO3)

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 NAICSa

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.
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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 website 

www.epa.gov/airtransport. 

C. What should I consider as I prepare my comments for EPA?

1. Submitting CBI. Do not submit this information to EPA 

through www.regulations.gov or e-mail. Clearly mark the part or 

all of the information that you claim to be CBI. For CBI 

information in a disk or CD ROM that you mail to EPA, mark the 

outside of the disk or CD ROM as CBI and then identify 

electronically within the disk or CD ROM the specific 

information that is claimed as CBI. In addition to one complete 

version of the comment that includes information claimed as CBI,

a copy of the comment that does not contain the information 

claimed as CBI must be submitted for inclusion in the public 

docket. Information so marked will not be disclosed except in 

accordance with procedures set forth in 40 CFR part 2. Send or 

deliver information identified as CBI only to the following 

address: Roberto Morales, OAQPS Document Control Officer (C404-

02), U.S. EPA, Research Triangle Park, NC 27711, Attention 

Docket ID No. EPA-HQ-OAR-2009-0491.
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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 3 public hearings on this proposal on 
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[ADD THE THREE DATES]. The hearings will be held at the 

following location(s): [ADD THE THREE LOCATIONS ADDRESSES AND 

PHONE NUMBERS]. The public hearings will begin at 9 a.m. and 

continue until 5 p.m., or later if necessary depending on the 

number of speakers. Oral testimony will be limited to 5 minutes 

per commenter. The EPA encourages commenters to provide written 

versions of their oral testimonies either electronically or in 

paper copy. Verbatim transcripts and written statements will be 

included in the rulemaking docket. If you would like to present 

oral testimony at 1 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; email: 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, 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 
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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 NOX 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 PM2.5, 24-Hour PM2.5, and 8-hour ozone? 

3. How did EPA assess interstate contributions to 

nonattainment and maintenance? 

4. What are the estimated interstate contributions to 

annual PM2.5, 24-hour PM2.5, and 8-hour ozone nonattainment 

and maintenance?

D. Proposed Methodology to Quantify Emissions that 

Significantly Contribute or Interfere With Maintenance 
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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 SO2 and Annual NOX State Emissions Budgets for 

EGUs

2. Defining Ozone Season NOX State Emissions Budgets for 

EGUs 

F. Emissions Reduction 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 Reduction Requirements

1. Date for Prohibiting Emissions That Significant 

Contribute or Interfere with Maintenance of the PM2.5 NAAQS 

2. Date for Prohibiting Emissions That Significant 

Contribute or Interfere 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 NOX 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
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4. State-level Emissions Projections

F. Transition from the CAIR Cap-and-trade Programs to 

Proposed Programs 

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

2. Change in States Covered

3. Applicability, CAIR Opt-ins and NOX SIP Call Units 

4. Early Reduction Provisions

5. Source Monitoring and Reporting

G. Interactions With Existing Title IV Program and NOX SIP 

Call 

1. Title IV Interactions

2. NOX SIP Call Interactions

VI. Stakeholder Outreach 

VII. State Implementation Plan Submissions

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

PM2.5 NAAQS

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

C. Transport Rule SIPs

VIII. Title V Permitting 

IX. What benefits are projected for the proposed rule?

A. The Impacts on PM2.5 and Ozone of the Proposed SO2 and NOX

Strategy

B. Human Health Benefit Analysis

C. Quantified and Monetized Visibility Benefits

D. Benefits of Reducing GHG Emission

E. Total Monetized Benefits 

F. How do the 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?
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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 LowIncome 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 SO2 and NOX 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 
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PM2.5 NAAQS promulgated in 1997, the 24-hour average PM2.5 NAAQS 

promulgated in 2006, and the ozone NAAQS promulgated in 1997.1 

These emissions are transported downwind either as SO2 and NOX

or, after transformation in the atmosphere, as fine particles or 

ozone. This notice identifies emission reduction 

responsibilities of upwind states, and also proposes enforceable 

FIPs to achieve the required emissions reductions in each state 

through cost-effective and flexible requirements for power 

plants. Each state will have the option of replacing these 

federal rules with state rules to achieve the required amount of 

emissions reductions from sources selected by the state.

With respect to the annual average PM2.5 NAAQS, this 

proposal finds that 24 eastern states have SO2 and NOx emission 

reduction responsibilities, and quantifies each state’s full 

emission reduction responsibility under section 

110(a)(2)(D)(i)(I). With respect to the 24-hour average PM2.5

NAAQS, this proposal finds that 25 eastern states have emission 

reduction responsibilities. The proposed reductions will at 

least partly eliminate, and subject to further analysis may 

fully eliminate, these states’ significant contribution and 

interference with maintenance for purposes of the 24-hour 

average PM2.5 standard. In all, emissions reductions related to 

 

1 In the context of the jurisdictions covered by this proposed 

rule, EPA uses the term “states” to include the District of 

Columbia.
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interstate transport 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 

NOx 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 SO2 emissions would be 5.0 million 

tons lower, annual NOX emissions would be 700,000 tons lower, and 

ozone season NOX emissions would be 100,000 tons lower in 2012, 

compared to baseline 2012 projections in the proposed covered 

states. Further, EGU SO2 emissions would be 4.6 million tons 

lower, annual NOX emissions would be 700,000 tons lower, and 

ozone season NOX emissions would be 100,000 tons lower in 2014, 

compared to baseline 2014 projections (which will have dropped 
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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 PM2.5 and ozone standards and take major strides 

toward helping states address nonattainment with the 2006 24-

hour average PM2.5 standard. See Table III.A-1 for proposed list 

of covered states. 

EPA is committed to fulfilling its responsibility to ensure 

that downwind states receive the relief from upwind emissions 

guaranteed under CAA section 110(a)(2)(D) For the 24-hour PM2.5

standard, EPA’s air quality modeling shows that in the areas 

with continuing non-attainment or maintenance problems, the

remaining exceedances occur almost entirely in the winter 

months. The relative importance of particle species such as 

sulfate and nitrate, is quite different between summer and 

winter. EPA is moving ahead before the final rule is published 

to determine the extent to which this wintertime problem is 

caused by emissions transported from upwind states. Further 

study of the 24-hour PM2.5 results could lead to a number of 

possible outcomes; EPA cannot judge the relative likelihood of 
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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 PM2.5 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 NOx

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 NOX control costs, emissions reductions, air 

quality impacts, and the nature of the residual air quality 

issues. EPA’s current information indicates that considering NOx

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 NOx 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 
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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 

“develop a comprehensive strategy for a cleaner and more 

efficient power sector with strong but achievable reduction 

goals for SO2, NOX, mercury, and other air toxics.”

In addition to this rule, other anticipated actions include 

a section 112(d) rule for electric utilities to be proposed by 

March 2011, potential rules to address pollution transport under 

revised NAAQS, revisions to new source performance standards for 

coal and oil-fired utility electric generating units, and best 

available retrofit technology (BART) and regional haze program 

requirements to protect visibility. These actions, and their 

relationship to this rule, are discussed further in section 

III.E.
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Ongoing reviews of the ozone and PM2.5 NAAQS could result in 

revised NAAQS. To address any new NAAQS, EPA would propose 

interstate transport determinations in future notices. Such 

proposals could require greater emissions reductions from states 

covered by this 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 SO2 and NOX emissions that contribute 

significantly to downwind nonattainment of the PM2.5 and ozone 

NAAQS promulgated in July 1997. The CAIR FIPs, promulgated 

April 26, 2006 (71 FR 25328), regulate EGUs in the covered 

states and achieve the emissions reductions requirements 

established by CAIR until states have approved SIPs to achieve 

the reductions. In July 2008, the D.C. Circuit Court found CAIR 

and the CAIR FIPs unlawful. North Carolina v. EPA, 531 F.3d 896 

(D.C. Cir. 2008). The Court’s original decision vacated CAIR. 

Id. at 929-30. However, the Court subsequently remanded CAIR to 
20

EPA without vacatur because it found that “allowing CAIR to 

remain in effect until it is replaced by a rule consistent with 

our opinion would at least temporarily preserve the 

environmental values covered by CAIR.” North Carolina v. EPA, 

550 F.3d 1176, 1178 (D.C. Cir. 2008). The CAIR requirements are

correctly in place and the CAIR’s regional control programs are 

operating while EPA develops replacement rules in response to 

the remand.

As described more fully in the remainder of this preamble, 

the approaches used in this proposed rule to measure and address

each state’s significant contribution to downwind nonattainment 

and interference with maintenance are guided by and consistent 

with the Court’s opinion in North 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
21

III and VII in this preamble and described in greater detail in 

[placeholder for cite to separate findings notice], EPA has 

determined, or proposed to determine, that the 32 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 PM2.5 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 this preamble, EPA is 

proposing a state-specific methodology to identify specific 

reductions that states in the eastern United States must make to 

satisfy the CAA section 110(a)(2)(D)(i)(I) prohibition on 

emissions that significantly contribute to nonattainment or 

interfere with maintenance in a downwind state. The proposed 

methodology uses state-specific inputs and focuses on the

emissions reductions available in each individual state to 

address the Court’s concern that the approach used in CAIR 

(which identified a single level of emissions achievable by the 

application of highly cost effective controls in the region) was 

insufficiently state specific. The proposed methodology uses 

air quality analysis to determine whether a state’s contribution 

to downwind air quality problems is above specific thresholds. 

If a state’s contribution does not exceed those thresholds, its 

contribution is found to be insignificant and it is no longer 
22

considered in the analysis. If a state’s contribution exceeds 

those thresholds, EPA takes a second step that uses a multifactor 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 PM2.5 NAAQS. It is 

based on cost and air quality considerations that are common to 

any NAAQS, but also calls for evaluation of facts specific to a 

particular NAAQS. As a result, application of the methodology 

to a revised, more stringent NAAQS might lead to a determination 

that greater reductions in transported pollution from upwind 

states are reasonable than for a current, less stringent NAAQS.

To facilitate implementation of the requirement that 

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 
23

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 SO2 and NOX budgets for each state covered for the 24-

hour and/or annual average PM2.5 NAAQS. EPA proposes an ozone 

season3 NOX 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 

 

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 NOX 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.
24

disruptions in electricity supply from other units. As a 

result, emissions could vary from year to year in a state where 

covered sources have installed all controls and taken all 

measures necessary to eliminate the state’s significant 

contribution and interference with maintenance. As described in 

detail in section IV of this preamble, EPA proposes to account 

for the inherent variability in power system operations through 

“assurance provisions” based on state variability limits which 

extend above the state emissions budgets. 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 PM2.5 NAAQS 

and the 1997 ozone NAAQS. The exception is for the 10 eastern 

states for which EPA has not completely quantified the total 

significant contribution or interference with maintenance with 

respect to the 1997 ozone NAAQS and the 15 states for which EPA 
25

has not completely quantified total significant contribution or 

interference with maintenance with respect to the 2006 PM2.5 NAAQS

in which case the FIPs would achieve measurable progress towards 

implementing that requirement.

The 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 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 sources through a 

program that uses state-specific budgets and allows intrastate 

and limited interstate trading. EPA is also taking comment on 

two alternative regulatory options. All options would achieve 

the 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 
26

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 emission rate limits. See

section V for further discussion of the remedy options.

The proposed remedy option and the first alternative, both 

of which are cap-and-trade approaches, would 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 SO2

and NOX 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 PM2.5

NAAQS promulgated in September 2006: Alabama, Connecticut, 

Delaware, District of Columbia, Georgia, Illinois, Indiana, 

Iowa, Kansas, Kentucky, Maryland, Massachusetts, Michigan, 
27

Minnesota, Missouri, Nebraska, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West 

Virginia, and Wisconsin.

EPA proposes to require reductions in SO2 and NOX 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 PM2.5 NAAQS promulgated 

in July 1997: Alabama, Delaware, District of Columbia, Florida, 

Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 

Virginia, West Virginia, and Wisconsin.

EPA also proposes to require reductions in ozone season NOX

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 SO2 and/or NOX emissions in the 32 covered 
28

states. The proposed FIPs would require the 28 jurisdictions 

covered for purposes of the 24-hour and/or annual PM2.5 NAAQS to 

reduce SO2 and NOX emissions by specified amounts. The proposed 

FIPs would require the 26 states covered for purposes of the 

ozone NAAQS to reduce ozone season NOX 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 PM2.5

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. With respect to 

the 1997 ozone NAAQS, EPA proposes to require an initial phase 

of NOX reductions starting in 2012 to ensure that reductions are 

made as expeditiously as practicable. EPA has determined, that 

for many states, these reductions will be sufficient to 

eliminate their significant contribution with respect to the 
29

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.

Table III.A-1 -- Lists of Covered States for PM2.5 and 

8-Hour Ozone NAAQS

State

Covered for 

24-Hour and/or 

Annual PM2.5

Required to 

Reduce SO2 and 

NOX

Covered for 

8-Hour Ozone

Required to 

Reduce Ozone 

Season NOX

Alabama X X

Arkansas X

Connecticut X X

Delaware X X

District of Columbia X X

Florida X X

Georgia X X

Illinois X X

Indiana X X

Iowa X

Kansas X X

Kentucky X X

Louisiana X X

Maryland X X

Massachusetts X

Michigan X X

Minnesota X

Mississippi X

Missouri X

Nebraska X

New Jersey X X

New York X X

North Carolina X X

Ohio X X

Oklahoma X

Pennsylvania X X

South Carolina X X
30

Tennessee X X

Texas X

Virginia X X

West Virginia X X

Wisconsin X

TOTALS 28 26

As discussed previously, EPA is proposing new SO2 and/or NOX

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 PM2.5 NAAQS in two tiers reflecting the 

stringency of SO2 reductions required to eliminate that state’s 

significant contribution to nonattainment and interference with 

maintenance. There would be a stringent SO2 tier comprising 15 

states (“group 1”) and a moderate SO2 tier comprising 13 states 

(“group 2”), with uniform stringency within each tier.4 For 

these same 28 states, there would be one annual NOX tier with 

uniform stringency of NOX reductions across all 28 states. 

 

4 With regard to interstate trading, the two SO2 stringency tiers 

would lead to two exclusive SO2 trading groups. That is, states 

in SO2 group 1 could not trade with states in SO2 group 2.
31

Similarly, for the 26 states covered for the ozone NAAQS there 

would be one ozone season NOX tier with uniform stringency across 

all 26 states.

The proposed stringent SO2 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 

SO2 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 SO2 and NOX reductions in the 28 states covered for 24-

hour and/or annual PM2.5 NAAQS. A second phase of reductions 

would be due in 2014, covering 2014 and thereafter. As 

described later, for certain states the 2014 reduction 

requirements would be more stringent, and for certain states 

would remain at the same level as the 2012 requirements.

For the 15 states in the stringent SO2 tier (“group 1”), the 

2014 phase would substantially increase the SO2 reduction 

requirements (i.e., these states would have smaller SO2 emissions 

budgets starting in 2014), reflecting the greater reductions 

needed to eliminate the portion of significant contribution and 
32

interference with maintenance that EPA has identified in this 

proposal from these states with respect to the 24-hour PM2.5

NAAQS. For the 13 states in the moderate SO2 tier (“group 2”),

the 2014 SO2 emissions budgets would remain the same as the 2012 

SO2 budgets for these states.

The 2014 annual NOX emissions budgets for all 28 states 

covered for the 24-hour and/or annual PM2.5 NAAQS would remain 

the same as the 2012 annual NOX budgets. 

With respect to the ozone NAAQS, EPA is proposing a single 

phase of reductions which begins in 2012. Thus, the rule does 

not call for any adjustment to be made to the 2012 ozone season 

NOX budgets for the 26 states covered for the ozone NAAQS. EPA 

intends to issue a subsequent proposal that would, among other 

things, address whether an additional phase of NOX reductions is 

necessary to address all significant contribution and 

interference with maintenance with respect to the 1997 ozone 

NAAQS. While this proposal assures downwind states that they 

will receive relief from upwind reductions that will help them 

achieve the NAAQS, EPA is committed to fulfilling its obligation 

to assure the downwind states that they receive the full relief 

they are entitled to under section 110(a)(2)(D). The Agency 

intends to quickly address any remaining significant 

contribution to nonattainment and interference with maintenance 

in a subsequent action that will also address a new more 
33

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.

Table III.A-2 – Projected SO2 and NOX EGU Emissions in Covered 

States With the Transport Rule5 Compared to Base Case6

Without Transport Rule or CAIR

(Million Tons) 

2012

Base Case

Emissions

2012 

Transport 

Rule 

Emissions

2012 

Emissions 

Reductions

2014

Base Case 

Emissions

2014 

Transport 

Rule 

Emissions

2014 

Emissions

Reductions

SO2 8.4 3.4 5.0 7.2 2.6 4.6

Annual 

NOX

2.0 1.3 0.7 2.0 1.3 0.7

Ozone 

Season 

NOX

0.7 0.6 0.1 0.7 0.6 0.1

Table III.A-3 – Projected SO2 and NOX EGU Emissions in Covered 

States With the Transport Rule Compared to 2005 Actual Emissions 

(Million Tons)

2005 

Actual

Emissions

2012 

Transport 

Rule 

Emissions

2012 

Emissions 

Reductions 

from 2005

2014 

Transport 

Rule 

Emissions

2014

Emissions 

Reductions 

from 2005

 

5 Projected Transport Rule emissions result from individual 

state budgets in the proposed approach and include some banking 

of allowances in 2012 and use of that bank in 2014.

6 EPA’s base case EGU emissions modeling does not assume 

enforceable SO2 or NOX reductions attributed to the Transport 

Rule or CAIR. In this base case, a unit with existing SO2 or NOX

control equipment, but without an enforceable federal or state 

control requirement, is allowed to choose its most economic 

approach to operation within existing Acid Rain Program 

requirements and may opt not to operate a control. See section 

IV.C.1 and the Electric Generation Modeling TSD for further 

information on the base case modeling.
34

2005 

Actual

Emissions

2012 

Transport 

Rule 

Emissions

2012 

Emissions 

Reductions 

from 2005

2014 

Transport 

Rule 

Emissions

2014

Emissions 

Reductions 

from 2005

SO2 8.9 3.4 5.5 2.6 6.3

Annual 

NOX

2.7 1.3 1.4 1.3 1.4

Ozone 

Season 

NOX

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 PM2.5 and ozone concentrations that are expected 

to result from the emissions reductions in 2014. The results of 

this modeling were used to calculate the average reduction in 

annual average PM2.5, 24-hour average PM2.5, and 8-hour ozone 

concentrations for monitoring sites in the eastern U.S. that are 

projected to be nonattainment in the 2014 base case. For annual 

PM2.5 and 24-hour PM2.5, the average reductions are 2.4 micrograms 

per cubic meter (μg/m3) and 4.3 μg/m3, respectively. The average 

reduction in 8-hour ozone at monitoring sites projected to be 

nonattainment in the 2014 base case is 0.3 parts per billion 

(ppb). The reductions in annual PM2.5, 24-hour PM2.5, and ozone 

concentrations for individual nonattainment and/or maintenance 

sites are provided in section IX. 

Table III.A-4 compares projected EGU emissions with the 

Transport Rule to projected EGU emissions with CAIR. 
35

Table III.A-4 – Simple Comparison of SO2 and NOX Emissions 

from Electric Generating Units in States in the CAIR or 

Transport Rule Regions* for Each Rule

2005 2012 2014

Actual Transport 

Rule CAIR** Transport Rule CAIR**

SO2 (Million Tons) 9.5 4.1 5.1 3.3 4.6

NOX (Million 

Tons)

Annual 2.9 1.6 1.7 1.6 1.7

Ozone Season 1.0 0.7 0.8 0.7 0.8

* Emissions totals include states covered by either the 

Transport Rule or CAIR. For PM2.5 (SO2 and annual NOX), 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 NOX), 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 SO2 totals are interpolations from emissions analysis 

originally done for 2010 and 2015. CAIR NOX 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 regionwide ozone season NOX cap and 

included PM2.5 requirements for the state of Arkansas). 

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 (section IX), economic impacts 

(section X), end-use energy efficiency (section XI), and 

statutory and executive order reviews (section XII).

B. Background

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

The statutory authority for this action is provided by the 
36

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 
37

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 NOX SIP Call, promulgated in 1998, was 

largely upheld by the U.S. Court of Appeals for the D.C. Circuit 

in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000). The CAIR, 

promulgated in 2005, was remanded by the D.C. Circuit in North 

Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008), modified on 

reh’g, 550 F.3d. 1176 (D.C. Cir. 2008). These decisions provide

additional guidance regarding the requirements of section 

110(a)(2)(D)(i)(I) and are discussed later in this section. 

Section 301(a)(1) of the CAA gives the Administrator of EPA 

general authority to “prescribe such regulations as are 

necessary to carry 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, EPA is clarifying the applicability of section 

110(a)(2)(D)(i)(I) by proposing to identify SO2 and NOX emissions 

that each affected state must prohibit pursuant to that section 
38

with respect to the PM2.5 NAAQS promulgated in 1997 and 2006 and 

the 8-hour ozone NAAQS promulgated in 1997. The improvements in 

air quality that would 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 
39

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 PM2.5 NAAQS and/or the 2006 PM2.5 NAAQS: (1) find 

that the state has failed to make a SIP submission required by 

section 110(a)(2)(D)(i)(I) or section 110(k)(5) of the Act; (2) 

find that such a SIP submission is incomplete; or (3) disapprove 

such a SIP submission. Once EPA has taken one of the these 

actions, pursuant to section 110(c)(1), it has authority to 

promulgate a FIP directly implementing the requirements of 

section 110(a)(2)(D)(i)(I), provided the state has not submitted 

and EPA has not approved a SIP submission that corrects the SIP 
40

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, healthrelated 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 which it is related to, 

consider the effects of fine particles on vulnerable populations 

(see further discussion in section XII.G and section XII.J of 

this notice). More detailed information on health effects of 

fine particles can be found on EPA’s Web site at:

http://epa.gov/pm/standards.html. 

In addition to effects on public health, fine particles are 

linked to a number of public welfare effects. First, PM2.5 are 
41

the major cause of reduced visibility (haze) in parts of the 

United States, including many of our national parks and 

wilderness areas. For more information about visibility, visit 

EPA’s website at www.epa.gov/visibility. Second, particles can 

be carried over long distances by wind and then settle on ground 

or water. The effects of this settling include: making lakes 

and streams acidic; changing the nutrient balance in coastal 

waters and large river basins; depleting the nutrients in soil; 

damaging sensitive forests and farm crops; and affecting the 

diversity of ecosystems. More information about these effects 

is available at EPA’s website at 

http://www.epa.gov/acidrain/effects/index.html. Finally, 

particle pollution can stain and damage stone and other 

materials, including culturally important objects such as 

statues and monuments. 

In 1997, EPA revised the NAAQS for PM to add new annual 

average and 24–hour standards for fine particles, using PM2.5 as 

the indicator (62 FR 38652). These revisions established an 

annual standard of 15 μg/m3 and a 24-hour standard of 65 μg/m3. 

During 2006, EPA revised the air quality standards for PM2.5. 

The 2006 standards decreased the level of the 24-hour fine 

particle standard from 65 μg/m3 to 35 μg/m3, and retained the 

annual fine particle standard at 15 μg/m3. 

In the preamble to the final rule for CAIR in May 2005, EPA 
42

discussed ambient monitoring for 2001-2003, the most recent 3-

year period available at the time. These results showed 

widespread exceedances of the 15 μg/m3 annual PM2.5 standard in 

the eastern United States, with additional exceedances in parts 

of California and one county in Montana. At that time, 82 

counties in the U.S. had at least one monitor that violated the 

1997 annual PM2.5 standard. 

The PM2.5 ambient air quality monitoring for the 2006-2008 

period (most recent available) shows significant improvements. 

Nonetheless, areas which continue to violate the 15 μg/m3 annual 

PM2.5 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 PM2.5

standard. 

The PM2.5 ambient air quality monitoring for this same 2006-

2008 time period shows that areas violating the 2006 24-hour 

PM2.5 standard of 35 μg/m3 (i.e., the revised 2006 standard for 

24-hour PM2.5) are located across much of the eastern half of the 

United States, in parts of California, and in some counties in 

several other western states – Alaska, Washington, Oregon, Utah, 

and Arizona. Based on these nationwide data, 52 counties have 

at least one monitor that violates the 24-hour PM2.5 standard. 

EPA believes that a great deal of the improvement in PM2.5
43

annual and 24-hour concentrations in the eastern U.S. can be 

attributed to EGU SO2 reductions achieved due to the CAIR. While 

the CAIR requirements related to SO2 did not begin until 2010, 

many actions were taken by EGU owners and operators in 

anticipation of those requirements. Emissions of SO2 from EGUs 

covered by the CAIR that were also in the acid rain program 

(under CAA Title IV) tracking system decreased from 10.2 million 

tons in 2005 to 7.6 million tons in 2008. Almost all of these 

emissions reductions were achieved in the areas of the Eastern 

United States covered by the CAIR. See

http://www.epa.gov/airmarkt/progress/ARP_4.html. EPA believes 

that there would be substantially more 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 PM2.5 standards. Information and documents related to this 

review are available at: 

http://epa.gov/ttn/naaqs/standards/pm/s_pm_index.html. EPA 

expects to complete this review and to publish any revised 

standards that may result from the review by July 2011. EPA is 

planning to propose the revised standards by December 2010. 

b. Ozone 

Short-term (1- to 3-hour) and prolonged (6-to 8-hour) 
44

exposures to ambient ozone have been linked to a number of 

adverse health effects. At sufficient concentrations, shortterm 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 short-term ozone exposure and premature mortality.

People who are particularly susceptible to the effects of 

ozone include people with respiratory diseases, such as asthma.

Those who are exposed to higher levels of ozone include adults 

and children who are active outdoors. This rule, and the NAAQS 

which it is related to, consider the effects of ozone on 
45

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 PM2.5 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 
46

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, for a number of areas still designated as 

nonattainment ozone monitoring data for 2006-2008 (most recent 

data available) show levels below the standard. EPA believes a 

number of factors contributed to NOx emissions reductions 

subsequent to the 2001-2003 time period. First, EGU emissions 

were substantially reduced as EGUs in the eastern U.S. came into 

compliance with the NOX SIP Call. A series of progress reports 
47

discussing the effect of the NOX SIP Call reductions can be found 

on EPA’s website at: 

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

Additional information on emissions and air quality trends are

available in EPA’s 2007 and 2008 air quality trends reports, 

which are available at: http://www.epa.gov/airtrends/.

Second, mobile source emissions standards for onroad 

gasoline and vehicle emissions standards began to reduce mobile 

source emissions as the fleet began turning over vehicles to 

meet tightened NOx emissions standards. Continued improvement 

in ozone is expected with continued reductions in mobile source 

emissions. 

On March 12, 2008, EPA published a revision to the 8-hour 

ozone standard, lowering the level from 0.08 ppm to 0.075 ppm. 

On September 16, 2009, EPA announced it would reconsider these 

2008 ozone standards. The purpose of the reconsideration is to 

ensure that the ozone standards are clearly grounded in science, 

protect public health with an adequate margin of safety, and are 

sufficient to protect the environment. EPA proposed revisions 

to the standards on January 19, 2010 (75 FR 2938) and will issue 

final standards by August 31, 2010. Information on the 2008 

revisions to the ozone standard, and on all subsequent activity 

based on the reconsideration, is available at: 

http://www.epa.gov/air/ozonepollution/actions.html#sep09s.
48

3. Which NAAQS does this proposal address?

This proposed action addresses the requirements of CAA 

section 110(a)(2)(D)(i)(I) as they relate to:

(1) the 1997 annual PM2.5 standards, 

(2) the 2006 daily PM2.5 standards, and

(3) the 1997 ozone standards 

The original CAIR and CAIR FIP rules, which pre-dated the

2006 standards, addressed the 1997 ozone and PM2.5 standards 

only. The 1997 8-hour ozone standard is 0.08 ppm. The 1997 

PM2.5 standards promulgated in 1997 established a 15 ug/3 standard 

for 24-hour PM2.5 and a 65 ug/m3 standard for annual PM2.5. In 

2006, the 24-hour PM2.5 standard was lowered to 35 ug/m3 and the 

15 ug/m3 annual PM2.5 standard was left unchanged. 

For this proposal, EPA fully addresses the requirements of 

CAA section 110(a)(2)(D)(i)(I) for the annual PM2.5 standard of 

15 ug/m3. For the 24-hour standard of 35 ug/m3 and for the 1997 

8-hour ozone standard of 0.08 ppm, EPA fully addresses the CAA 

section 110(a)(2)(D)(i)(I) requirements for some states, but for 

the remaining states EPA will address whether further 

requirements are needed. 

This action does not address the CAA section 

110(a)(2)(D)(i)(I) requirements for the revised ozone standards 

promulgated in 2008. These standards are currently under 

reconsideration. We are, however, actively conducting the 
49

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 
50

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 
51

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.
52

The CAA further addresses interstate transport of pollution 

in section 126, which Congress revised slightly in 1990. 

Subsection (b) of that provision authorizes each state (or 

political subdivision) to 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 NOx

emissions throughout the region. In 1999 through 2002, most of 

the OTC states achieved substantial NOx reductions through an 

ozone season cap and trade program for NOx called the OTC NOx

Budget Program, which EPA administered, and through NOX emission 

rate limits from certain coal plants under Title IV. 

 

7 In addition, section 115 authorizes EPA to require a SIP 

revision in certain circumstances when one or more sources 

within a state "cause or contribute to air pollution which may 

reasonably be anticipated to endanger public health or welfare 

in a foreign country."
53

Separate from activity in the OTC, EPA and the 

Environmental Council of the States (ECOS) formed the OTAG in 

1995. This workgroup brought together interested states and 

other stakeholders, including industry and environmental groups. 

Its primary objective was to assess the ozone transport problem 

and develop a strategy for reducing ozone pollution throughout 

the eastern half of the United States.

Notwithstanding significant efforts, the states generally 

were not able to meet the November 15, 1994 statutory deadline 

for the attainment demonstration and rate of progress (ROP) SIP 

submissions required under section 182(c). The major reason for 

this failure was that at that time, states with downwind 

nonattainment areas were not able to address transport from 

upwind areas. As a result, EPA recognized that development of 

the necessary technical information, as well as the control 

measures necessary to achieve the large level of reductions 

likely to be required, had been particularly 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 

modeling into their local plans, EPA extended the submittal date 
54

to April 1998.8 The OTAG’s air quality modeling and 

recommendations formed the basis for what became the NOx 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 

 

8 Guidance for Implementing the 1-hour Ozone and Pre-Existing 

PM10 NAAQS, Memorandum from Richard D. Wilson, dated December 29, 

1997.
55

published the NPR for the NOX SIP call by notice dated November 

7, 1997 (62 FR 60319). The NPR proposed to make a finding of 

significant contribution due to transported NOX emissions to 

nonattainment or maintenance problems downwind and to assign NOX

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 NOX 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 costeffective 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 NOX budget trading program and state reporting 

requirements and provided the air quality analyses of the 

proposed statewide NOX emissions budgets. 

Revision of the Ozone NAAQS. On July 18, 1997 (62 FR 

38856), EPA issued its final action to revise the NAAQS for 

ozone. The EPA’s decision to revise the standard was based on 

the Agency’s review of the available scientific evidence linking 

exposures to ambient ozone to adverse health and welfare effects 
56

at levels allowed by the pre-existing 1-hour ozone standards. 

The 1-hour primary standard was replaced by an 8-hour standard 

at a level of 0.08 ppm, with a form based on the 3-year average 

of the annual fourth-highest daily maximum 8-hour average ozone 

concentration measured at each monitor within an area. The new 

primary 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 

protection to the public welfare against ozone-induced effects 

on vegetation.

Section 126 Petitions. In a separate rulemaking, EPA 

proposed action on petitions submitted by 8 northeastern states9

under section 126 of the CAA. Each petition specifically 

requested that EPA make a finding that NOX emissions from certain 

major stationary sources significantly contributed to ozone 

nonattainment problems in the petitioning state. Both the NOX

SIP call and the section 126 petitions were designed to address 

ozone transport through reductions in upwind NOX emissions.

However, the EPA's response to the section 126 petitions 

 

9

The 8 states were Connecticut, Massachusetts, Maine, New 

Hampshire, New York, Pennsylvania, Rhode Island, and Vermont.
57

differed from EPA's action in the NOX SIP call rulemaking in 

several ways. In the NOX 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 NOX 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. NOx SIP Call

Based on the findings of OTAG, EPA proposed a rulemaking 

known as the NOx 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 NOX emissions in 22 states and 

the District of Columbia contribute to ozone nonattainment in 

other states, and the rule required affected states to amend 
58

their SIPs and limit NOX emissions. EPA set an ozone season NOX

budget for each affected state, essentially a cap on ozone 

season (summertime) NOX 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 NOX SIP call 

rule, the Court issued two decisions concerning the NOX SIP call 

and its technical amendments.10 The Court decisions, discussed 

later, generally upheld the NOX 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 NOX 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 NOX SIP call based on the 8-hour NAAQS (65 FR 

56245, September 18, 2000). Therefore, for the most part, the 

Court did not address NOX SIP call requirements under the 8-hour 

ozone NAAQS. 

(1) What was the NOX SIP call?

The NOX SIP call was EPA’s principal effort to reduce 

interstate transport of precursors for both the 1-hour ozone 

 

10 See Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000), cert. 

denied, 532 U.S. 904 (2001) (NOX SIP call) and Appalachian Power 

v. EPA, 251 F.3d 1026 (D.C. Cir. 2001) (technical amendments).
59

NAAQS and the 8-hour ozone NAAQS. The EPA’s rulemaking was 

based on its consideration of OTAG’s recommendations, as well as 

information resulting from EPA’s additional work, and extensive 

public input generated through notice-and-comment rulemaking. 

The EPA believed that requiring NOX 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 NOX 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 NOX control measures to mitigate the significant ozone 

transport during summer months known as the “ozone season” (MaySeptember). 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
60

amounts of emissions reductions. By eliminating these amounts 

of NOX emissions, the control measures would assure that the 

remaining NOX emissions would meet the level identified in the 

rule as the state’s NOX 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 NOX 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 NOx SIP call.

(2) Legal Challenges to the NOX SIP Call 

Several petitioners challenged the NOX SIP Call in the 

United States Court of Appeals for the District of Columbia 

Circuit (D.C. Circuit). In Michigan v. EPA, 213 F.3d 663 (D.C. 

Cir., 2000), cert. denied, 532 U.S. 904 (2001), the Court upheld 

the rule in most respects. Of greatest relevance here, the 
61

Court upheld the essential features of EPA’s approach to 

identifying and eliminating states’ NOX emissions that 

significantly contribute to downwind nonattainment. It upheld 

key aspects of EPA’s air quality 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 NOX 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 (D.C. Cir. 2000). 

The decision resolved only issues involving the 1-hour 

ozone NAAQS and did not resolve any issues involving the 8-hour 

NAAQS, which provided another basis for the rule. See id. at 

670-71. EPA ultimately stayed the 8-hour basis of the NOX SIP 

Call. See 65 FR 56245. In addition, in a subsequent case that 

reviewed separate EPA rulemakings making technical corrections 
62

to the NOX SIP Call, the D.C. Circuit remanded the case for a 

better explanation of EPA’s methodology for computing the growth 

component in the EGU heat input calculation. See Appalachian 

Power Co. v. EPA, 251 F.3d 1026 (D.C. Cir. 2001). More 

recently, the Court also rejected a challenge to a subsequent 

EPA rule withdrawing EPA’s findings of significant contribution 

for Georgia for the 1-hour ozone standard. See North Carolina 

v. EPA, 587 F.3d 422 (D.C. Cir. 2009). 

(3) How the NOX Budget Trading Program (NBP) Worked

The NBP was a market-based cap and trade program created to 

reduce the regional transport of emissions of NOX 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 NOX

emissions from affected sources, contributing to improvements in 

regional air quality across the Midwest, Northeast, and MidAtlantic. 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 NOX emissions decreased from levels in baseline years in 

all states participating in the NBP. (All NBP states 

transitioned to the CAIR NOX 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 
63

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 NOX reductions that have led to 

improvements in ozone and PM2.5 saving 580-1,800 lives annually in 

200811. 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 NOX ozone season 

trading program to achieve this.

See section V.D.4.e. for a discussion of the results of the 

NOX Budget Trading Program.

(4) Clean Air Interstate Rule

Following promulgation of the new NAAQS in 1997, the CAA 

required all 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 

 

11 U.S.EPA. September, 2009. The NOx Budget Trading Program: 2008 

Environmental Results, p.9
64

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 to submit, 

within a specified period, a SIP revision to correct the 

inadequacy (‘‘SIP call’’). In 1998, EPA used this authority to 

issue the NOX SIP call, discussed previously, to require states 

to revise their SIPs to include measures to reduce NOX emissions 

that were significantly contributing to ozone nonattainment 

problems in downwind states. 

Sulfur dioxide and NOX are not the only emissions that 

contribute to interstate transport and PM2.5 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 PM2.5 emissions or organic 
65

precursors (e.g., volatile organic compounds (VOCs) or ammonia 

(NH3)). 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 NOX, rather than 

VOCs.12

(5) What is the CAIR? 

The CAA contains a number of requirements to address 

nonattainment of the PM2.5 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 PM2.5, 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 SO2 and/or 

 

12 The OTAG was active from 1995–1997 and consisted of 

representatives from the 37 states in that region; the District 

of Columbia; EPA; and interested members of the public, 

including industry and environmental groups. See discussion 

below under NOX SIP Call for further information on OTAG.

13 The term ‘‘transport’’ includes the transport of both PM2.5 and 

their precursor emissions and/or transport of both ozone and its 

precursor emissions.
66

NOX -- important precursors of PM2.5 (NOX and SO2) and ozone (NOX)-

- 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 PM2.5 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 NOX SIP call to 

address interstate pollution transport for ozone, and was EPA’s 

first attempt to address interstate pollution transport for 

PM2.5. It required significant reductions in emissions of SO2 and 

NOX, which contribute to fine particle concentrations. In 

addition, NOX emissions contribute to ozone problems. EGUs were 

found to be a major source of the SO2 and NOX emissions which 

contributed to fine particle concentrations and ozone problems 

downwind.

CAIR was designed to provide significant air quality 

attainment, health, and environmental improvements across the 

eastern U.S. in a highly cost-effective manner by reducing SO2
67

and NOX emissions from EGUs that contribute to the PM2.5 and 8-

hour ozone problems described in the rule. CAIR’s emissions 

reductions requirements were based on controls that EPA had 

determined to be highly cost-effective for EGUs under optional 

cap and trade programs. However, states had the flexibility to 

choose the measures to adopt to achieve the specified emissions 

reductions. EPA required the emissions reductions to be 

implemented in two phases, with the first phase in 2009 and 2010 

(for NOX and SO2, 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 SO2 and/or NOX that each of the identified 

states must meet through SIP measures.

Section V.D.1 discusses the approach taken in CAIR using 

three model multi-state cap and trade programs for SO2 and NOX

that EPA developed and that states could choose to adopt to meet 

the required emissions reductions in a flexible and costeffective 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 
68

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 PM2.5 NAAQS. 

States were to have submitted 110(a)(2)(D)(i) SIPs for those 

standards by July 2000. This action triggered a 2-year clock 

for EPA to issue 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 
69

SO2 emissions, (2) annual NOX emissions, and (3) ozone season NOX

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 NOX 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 SO2 and NOX emissions because they contribute 

to PM2.5 nonattainment in other states. 71 FR 25288, April 28, 

2006. These states were already included in the CAIR because 

their sources contributed to nonattainment of other states’ 8-

hour ozone air quality standard. The CAIR FIP 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 D.C. 

Circuit. In North Carolina v. EPA, 531 F.3d 896, modified on 
70

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 
71

air quality modeling portion of the significant contribution 

analysis for PM2.5, EPA’s use of whole states as the unit of 

measurement, and the first-phase NOX 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. 
72

The Court further rejected the state budgets for SO2 and NOX

which were used to implement the CAIR trading programs, finding 

the budgets to be insufficiently related to the 

110(a)(2)(D)(i)(I) mandate of eliminating significant 

contribution and interference with maintenance. See id. at 916-

21. It also rejected EPA’s effort to harmonize the CAIR SO2

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 SO2 and NOX in the eastern United States. As 

explained previously, although the D.C. Circuit remanded the 

rule to EPA, it did so without vacatur allowing the rule to 
73

remain in effect while EPA addresses the remand. Thus, CAIR is 

continuing to help states address ozone and PM2.5 nonattainment 

and improve visibility, reducing transported precursors of SO2

and NOX, through the implementation of three separate cap and 

trade compliance programs for annual NOX, ozone season NOX, and 

annual SO2 emissions from power plants. 

See section V.D.4.e. for a discussion on CAIR 

implementation in 2009, the first year of the NOX annual and 

ozone season programs. The CAIR annual SO2 program began January 

1, 2010. Quarterly emissions will be posted on EPA’s web site 

(see http://www.epa.gov/airmarkets) and an assessment of 

emissions reduction data will be available at the end of each

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 
74

rule. North Carolina v. EPA, 531 F.3d 896, modified on reh’g, 

550 F.3d 1176 (D.C. Cir. 2008).

The action EPA is proposing would respond to the July and 

December 2008 opinions of the D.C. 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 SO2, annual 

NOX and ozone season NOX 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 

measureable progress towards eliminating emissions of SO2 and NOX

that significantly contribute to or interfere with maintenance 
75

of the 1997 and 2007 PM2.5 NAAQS and the 1997 ozone NAAQS in the 

eastern half of the United States. 

b. Address Transport Requirements With Respect to the Existing 

PM2.5 Standards 

This proposed rule is designed to address the requirements 

of section 110(a)(2)(D)(i)(I) of the CAA as they relate to the 

1997 and 2006 PM2.5 standards for states in the eastern United 

States. The proposed rule would both identify the emissions 

from states in the eastern U.S. that significantly contribute to 

nonattainment and interfere with maintenance of the NAAQS in 

downwind states, and prohibit such emissions.

States are obligated to submit SIPs to EPA addressing the 

provisions of section 110(a)(2), including the transport 

provisions of section 110(a)(2)(D)(i)(I), within 3 years of the 

promulgation of a new or revised NAAQS. For the 1997 NAAQS, 

these SIPs were due in 2000. On April 25, 2005 (effective May 

25, 2005) EPA issued findings that states had failed to submit 

SIPs to satisfy the requirements of section 110(a)(2)(D)(i) of 

the Act under the 1997 ozone and PM2.5 standards. 70 FR 21147, 

April 25, 2005. These findings started a 2-year clock for the 

promulgation of a FIP by EPA unless, prior to that time, each 

state makes a submission to meet the requirements of 

110(a)(2)(D)(i) and EPA approves the submission. This 2-year 

period expired in May 2007. Because the Court found CAIR 
76

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 PM2.5 standards were signed by the 

Administrator on September 21, 2006, and published in the 

Federal Register on October 17, 2006. 71 FR 61144. The 

revisions were effective December 18, 2006. EPA interprets the 

3 year deadline for submission of 110(a)(2) SIPs to be 3 years 

from the date of signature. Accordingly, for the 2006 revisions 

to the PM2.5 NAAQS, the SIPs under 110(a)(2) were due on 

September 21, 2009. On [ADD CITE TO FINDINGS NOTICE] 2010, EPA 

issued a notice making findings that states had not submitted 

SIPs under the 2006 PM2.5 NAAQS by the September 2009 deadline. 

These findings started a 2-year clock for the promulgation of a 

FIP by EPA unless, prior to that time, each state makes a 

submission to meet the requirements of 110(a)(2)(D)(i)(I) and 

EPA approves the submission. This 2-year period will expire on 

[add date 2 years from notice of findings]. This proposal is 

designed to provide FIPs for the 2006 standards to ensure that 

the 110(a)(2)(D)(i)(I) obligation is fully satisfied as it 
77

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
78

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 
79

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 
80

precisely identify local emissions control measures that may be 

available in a particular area. The EPA continues to believe 

that a strategy based on adopting cost effective controls on 

transported pollutants as a first step will produce a more 

reasonable, equitable, and optimal strategy than one beginning 

with local controls. The local measures 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 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 SO2 and NOX.

In conclusion, EPA believes that the proposed rule 

represents the best approach for identifying upwind state 

emissions that significantly contribute to nonattainment in, or 

interfere with maintenance by, downwind states. 

b. Ensuring That Pollution Controls Operate

The proposed Transport Rule would, by 2012, cap emissions 

of SO2 and NOX on a state-by-state basis and guarantee that 

existing and planned pollution controls operate. EPA is 

convinced that the considerable benefits to air quality and 

public health that have been achieved must be ensured going 
81

forward. Keeping emissions of SO2 and NOx from increasing by 

2012 in 27 states and DC assures that recent gains are 

maintained and that states that significantly contribute to 

downwind PM2.5 nonattainment and maintenance areas do 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 
82

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 costeffectiveness 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 PM2.5 and ozone is a 
83

substantial and critical component for attaining the ozone and 

PM2.5 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 serves 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 PM2.5 standards 

in the western United States. At the time, the only exceedances 

of the 15 μg/m3 in those states were in parts of California, and 

in Lincoln County (Libby), Montana. The Montana location has 

subsequently come into attainment. 

Technical information developed for EPA’s recently 

completed nonattainment designations suggests that interstate 

emission transport makes a relatively small contribution to 

exceedances in the western United States under the 2006 PM2.5

standards. For these designations, EPA identified several 

locations in the western U.S. with exceedances of the 24-hour 

PM2.5 standards. These locations were in California and other a 

few other western states: Alaska, Washington, Oregon, Utah, and 

Arizona. Technical support information describing the nature of 

the 24-hour PM2.5 problem at each of these locations is available 

at: http://www.epa.gov/pmdesignations/2006standards/tech.htm. A 

review of this information suggests to EPA that the Western 
84

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 SO2, NOX, 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 SO2, NOX, mercury, and other air toxics. To the 

extent that the Agency has the legal authority to do so while 

fulfilling its obligations under the Act and other relevant 

statues, the Agency will also coordinate these utility-related 

air pollution rules with upcoming regulations for the power 

sector from EPA’s Office of Water (OW) and its Office of 

Resource Conservation and Recovery (ORCR). EPA expects that 

this comprehensive set of requirements will yield substantial 

health and environmental benefits for the public, benefits that 
85

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 CAA 

Section 112(d) standards; 4) revisions to the NSPS for coal and 

oil-fired electric utility steam generating units; and 5) best 

available retrofit technology (BART) requirements and other 

requirements that address visibility and regional haze. Within 

the planning and investment horizon for compliance with these 

rules, the EPA very likely will be compelled to respond a 

pending petition to set standards for the emissions of 

greenhouse gases from steam electric generating units under the 
86

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 BACT for their GHG. 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 is included later.

Transport Rule. This proposed transport rule includes 

emissions reductions requirements for EGUs to address interstate 

transport under the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS, and 

the 2006 PM2.5 NAAQS. 

Rules to Address Transport under Revised Air Quality 

Health Standards. EPA is currently reviewing both the ozone and 

fine particle NAAQS. If revised NAAQS are promulgated, they may 

result in additional requirements to reduce utility emissions to 

address transport. The ozone standard review will be completed 

by August 31, 2010, and the fine particle review by July 2011. 
87

State implementation plan deadlines and attainment deadlines 

will flow from those dates. 

Section 112(d) Standards for Utility Units. In 2008, the 

D.C. Circuit Court vacated the CAMR and the 112(n) Revision 

Rule, which removed coal- and oil-fired electric utility 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 HAP emitted from these 

sources. As required by section 112, EPA will issue a set of 

emission standards. In part, the section 112(d) rule will 

require that 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 bestperforming 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, 
88

including stack testing results, by September 2010. EPA has 

agreed to sign the proposed rule by March 16, 2011, and sign the 

final rule no later than November 16, 2011. EPA may provide 

existing sources up to 3 years to comply with section 112(d) 

standards, and the CAA authorizes the permit authority to grant 

a 1 year extension of the compliance date on a case-by-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, compliance would generally be required 

by early 2015.

In developing these rules, EPA will endeavor to proceed in 

a way that provides all stakeholders and other federal, state 

and local decision-makers with ongoing, up-to-date information 

about the full suite of environmental responsibilities that the 

power sector must undertake. This, in turn, will enable power 

companies and others whose policies and decisions affect their 

investment choice to adopt compliance strategies that take full 

advantage of co-control opportunities and efficiencies and other 

approaches to maximizing the cost-effectiveness and leveraging 

benefits of their investments.

New Source Performance Standards. NSPS are administered 

under section 111 of the CAA. The standards for new, modified, 
89

and reconstructed steam EGUs are contained in 40 CFR Part 60 

subpart Da, which was last amended in 2006. The current 

structure of subpart Da sets output-based (i.e., lbs of 

emission/MWh) emission limits for NOX and SO2 and optional 

output-based standards for particulate matter. EPA is currently 

re-evaluating the specific emission limits in Subpart Da to 

determine whether they reflect the degree of emission limitation 

achievable through the application of the best system of 

emission reduction, which the Administrator determines has been 

adequately demonstrated. The current NSPS covers any new, 

reconstructed, or modified unit. 

Regional Haze/BART. States are required to develop SIPs 

that address regional haze in scenic areas such as 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 
90

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 
91

governments as well, through building codes, zoning, and other 

actions, can and do promote end-use 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. The Administration is committed to meeting this 

challenge. 

Non-Air Office Regulations. EPA is also working on three 

additional rules that will have potential impacts on the power 

sector. ORCR is issuing revised regulations dealing with coal 

combustion residues in early Spring 2010, which are the 

combustion byproducts associated with the use of coal as a fuel. 

OW is issuing two rules over the next several years. One will 

regulate cooling water intake structures. The other will revise 

the effluent guidelines for wastewater discharges from power 

plants. Each of these rules has cost implications to the power 

sector, and the Agency intends to coordinate these regulations 

with the upcoming air regulations. We intend to maximize 
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reductions in pollution while maintaining cost-effective 

solutions.

As a first step to carrying out its commitment to promote 

and facilitate the most cost-effective and forward-looking 

compliance investments and strategies on the part of the power 

sector, EPA will conduct extensive outreach concerning the full 

range of the upcoming environmental responsibilities of the 

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 SO2 and NOX reductions to help smooth transition 

to compliance with the Section 112(d) standards applicable to 

utility units. 

At the same time EPA also intends to expand its outreach to 

others –- including Public Utility Commissions (PUCs) and State 

Energy Offices, FERC, and Department of Energy (DOE) -– who can 

play a significant role in promoting or requiring investment in 

energy efficiency. EPA intends to continue these efforts over 
93

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 PM2.5 and ozone NAAQS downwind. 

The section begins by providing background on how “significant 

contribution” and “interference with maintenance” were defined 

in the past by EPA for the NOX 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 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 
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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 NOX SIP Call and the CAIR

a. Significant Contribution 

Two rules EPA promulgated that address interstate transport 

of pollutants are the NOX 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 
95

as the “significant contribution.” The approach used in each 

rule is described in more detail, later.

NOX SIP Call. EPA addressed the section 110(a)(2)(D)(i)(I) 

requirement to prohibit emissions that significantly contribute 

to downwind nonattainment in the NOX 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) 

 

14 In the NOX 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 NOX SIP Call, EPA stated that the 

“interfere with maintenance” test applied with respect to only 

the 8-hour ozone NAAQS (63 FR 57379-80). 
96

determining the amount of that state’s emissions that can be 

eliminated through the application of cost-effective controls 

(63 FR 57403).

Air Quality Factor. The first factor that EPA used to 

determine the amount of emissions that significantly contribute 

to downwind nonattainment was the air quality factor, consisting 

of an evaluation of the impact on downwind air quality of the 

upwind state’s emissions.

EPA specifically considered three air quality factors 

with respect to each upwind state:

 The overall nature of the ozone problem (i.e., 

“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 

nonattainment problems. EPA considered the then-current air 

quality of the area, the predicted future air quality (assuming 
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implementation of required controls but not the transport 

requirements that were the subject of the NOX 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 

 

15 EPA explained in the NOX 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 NOX), only the NOX emissions had meaningful interstate 

impacts. 
98

nonattainment area (63 FR 57378). EPA referred to states with 

emissions that had a sufficiently great impact as significant 

contributors; however, the precise amount of their significant 

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 NOX

emissions may be eliminated through controls that, on a costper-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 were both: 

(a) from states that exceeded the air quality thresholds and (b) 

could be eliminated through the application of highly costeffective 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 
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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 were cost effective, if not 

highly cost effective - remained available to the states.

Determination of Highly Cost-Effective Amount. EPA 

determined the dollar amount considered to be highly cost 

effective by reference to the cost-effectiveness of recently 

promulgated or proposed NOX controls. EPA determined that the 

average cost effectiveness of controls ranged up to 

approximately $1,800 per ton of NOX removed (1990$) 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 costeffectiveness 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 NOX SIP Call concerned the ozone standard, for which 
100

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 
101

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 NOX 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 NOX 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 NOX emissions that each state was required to reduce on 

grounds that those emissions contribute significantly to 

nonattainment downwind. The total amount of required NOX

emissions reductions was the sum of the amounts that would be 

reduced by application of highly cost-effective controls to each 
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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 NOX 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 NOX SIP Call had addressed significant 

contribution with respect to the 1997 ozone NAAQS, the CAIR 

addressed significant contribution with respect to both the 

ozone and annual PM2.5 NAAQS promulgated in 1997. In the CAIR, 

EPA used a methodology to identify states’ significant 

contribution based on and very similar to the methodology used 

in the NOX 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 
103

nonattainment areas, and the cost factor of highly costeffective controls. See 70 FR 25174.

Air Quality Factor – PM2.5. EPA employed air quality 

modeling techniques to assess the impact of each upwind state’s 

entire inventory of anthropogenic SO2 and NOX emissions on 

downwind nonattainment and maintenance for the annual PM2.5

NAAQS.17 EPA determined that upwind NOX and SO2 emissions 

contribute significantly to annual PM2.5 nonattainment as of the 

year 2010.

As in the NOX 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 μg/m3 for 

PM2.5. An upwind state with contributions to downwind 

nonattainment below this level would not be subject to 

regulatory requirements, but a state with contributions at or 

higher than this level would be subject to further evaluation 

(70 FR 25174-75).

This level reflects the fact that PM2.5 nonattainment, like 

ozone, is caused by many sources in a broad region and therefore 

may be solved only by controlling sources throughout the region. 

As with the NOX SIP Call, the collective contribution condition 

 

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

annual PM2.5 NAAQS.
104

of PM2.5 air quality is reflected in the relatively low threshold 

(70 FR 25175).

Air Quality Factor – 8-Hour Ozone. EPA employed air 

quality modeling techniques to assess the impact of each upwind 

state’s inventory of NOX and VOC emissions on downwind 

nonattainment. The EPA determined that upwind NOX emissions 

contribute significantly to 8-hour ozone nonattainment as of the 

year 2010. Therefore, EPA projected NOX 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 NOX 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 NOX SIP Call, EPA interpreted 

this factor as mandating emissions reductions in amounts that 
105

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 costeffective SO2 and NOX 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 NOX

SIP Call, EPA analyzed the costs of control on a regionwide 

basis.

Other Factors. As with the NOX SIP Call, EPA considered 

other factors that influence the application of the air quality 

and cost factors, and that confirm the conclusions concerning 

the amounts of emissions that upwind states must eliminate as 

contributing significantly to downwind 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 NOX SIP Call and in the CAIR, EPA gave the term 

“interfere with maintenance” a meaning much the same as the 
106

meaning given to the term “significant contribution.” That 

approach, which was found inconsistent with the requirements of 

110(a)(2)(D)(i)(I) are described later. EPA’s proposed new 

approach to interpreting “interfere with maintenance” is 

described in section IV.D, later.

NOX SIP Call: In the NOX 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-with-maintenance” issue, 

which is identifying the downwind areas whose maintenance 

of the NAAQS may suffer interference due to upwind 

emissions. The EPA has analyzed the "interfere-withmaintenance" 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 same positions with 

respect to the interfere-with-maintenance test as described 

in the notice of proposed rulemaking. 

In addition, the NOX 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 
107

"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

 

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.”
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In responding to comments on the CAIR proposal, we also 

used this interpretation of the maintenance provision to help 

support the need for Phase II CAIR reductions. For ozone, we 

conducted an analysis that looked at (1) the amount by which 

receptor locations were projected to attain in 2015 and (2) the 

year-to-year variability in ozone levels due to weather and 

other factors based on a review of historical monitoring data. 

This analysis concluded that areas within 3-5 ppb of the 

standard, and sometimes greater (e.g., Fulton County, Atlanta) 

had historic variability as great as 8 ppb, and that this 

variability suggests strongly that upwind states could be 

interfering with maintenance even if modeling shows attainment 

by up to these amounts. For PM2.5, while we lacked historical 

data to support the same variability analysis, we characterized 

attaining the annual standard by 0.5 ug/m3 as “attaining by a 

narrow margin” thus giving rise to maintenance concerns, and 

noted that in past (mobile source) rules we had indicated that 

attainment by a margin of 10 percent or less could be considered 

to raise maintenance concerns.

2. Judicial Opinions

a. Significant Contribution

In North Carolina v. EPA, 531 F.3d. 896 (D.C. Cir. 2008), 

the Court held that the approach EPA used in CAIR to measure

each state’s significant contribution was insufficient. EPA, 
109

the Court concluded, had failed to “measure[] the significant 

contribution from sources within an individual state to downwind 

nonattainment areas.” Id. at 907. The Court further reasoned 

that the lack of a state-specific significant contribution 

analysis made it impossible for EPA to show that the trading 

programs and state budgets established to implement the trading 

programs, effectuated the section 110(a)(2)(D)(i)(I) statutory 

mandate to eliminate emissions within the state that 

significantly contribute to nonattainment or interfere with 

maintenance in other states.

Specifically, the court rejected the regional scope of 

EPA’s analysis. It reasoned that “because EPA evaluated whether 

its proposed emissions were ‘highly cost 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 

(D.C. 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”. 
110

Id. The Court also recognized that Michigan approved EPA’s 

decision to apply a uniform emissions control requirement to all 

upwind states despite different levels of contribution. See

North Carolina, 531 F.3d at 908. The Court thus concluded that 

while EPA must “measure each state’s ‘significant contribution’ 

to 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 PM2.5 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 

PM2.5 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. 
111

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 nonattainment 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 

NOX SIP Call but modified to address the concerns raised by the 

Court. In the first step of this proposed approach, EPA uses 

air quality modeling to quantify individual states’ 

contributions to downwind nonattainment and maintenance sites in 

2012. States whose contributions to any downwind sites are 

greater than 1 percent of the relevant NAAQS are considered 

“linked” to those sites for the purpose of the second step in 

the analysis. In the second step, EPA identifies the portion of 

each state’s contribution that constitutes its “significant 

contribution” and “interference with maintenance.” To do so, 

EPA uses maximum cost thresholds, informed by air quality 
112

considerations. Specifically, for each precursor pollutant(i.e. 

SO2 and NOX for PM2.5 and NOX for ozone) emitted by the upwind 

states that EPA has identified as linked to NAAQS nonattainment 

and maintenance sites downwind, EPA identifies, through this 

process the reductions available in each individual upwind state 

at the appropriate maximum 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 NOX

SIP Call, are informed by air quality considerations, in 

addition to a comparison of the cost of control in other 

regulatory contexts. Specific cost thresholds were developed 

for annual SO2, annual NOX, and ozone-season NOX. Where 

appropriate, EPA developed higher and lower cost thresholds,

based on the downwind air quality impact of emissions from 

different groups of states. Although EPA in the past has 

applied a uniform remedy to all states found to have a 

significant contribution, in this proposal EPA divides, for 

individual pollutants, the significantly contributing states 

into two groups – those whose significant contribution can be 

eliminated at a lower cost threshold, and those whose 

significant contribution is not eliminated (to the extent that 

is has been identified in today’s proposal) until they reach the 

higher cost threshold. The lower cost threshold applies to a 
113

state, if the reduction in emissions at that threshold 

eliminates nonattainment and maintenance problems at all 

“linked” sites. 

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. 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. 
114

A key step in the process of developing a 

110(a)(2)(D)(i)(I) rule involves analyzing existing (base case) 

emissions to determine which states significantly contribute to 

downwind nonattainment and maintenance areas. EPA cannot

prejudge at this stage which states will be affected by the 

rule. For example, a state affected by CAIR may not be affected 

by the new rule and after the new rule goes into effect, the 

CAIR requirements will no longer apply. For a state covered by 

CAIR but not covered by the new rule, the CAIR requirements 

would not be replaced with new requirements, and therefore an 

increase in emissions relative to present levels could occur in 

that state. More fundamentally, the court has made clear that, 

due to 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 
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absence of the CAIR NOX program will lead to the status quo of 

the NOX Budget Program, which limits ozone-season NOX emissions 

and ensures the operation of NOX controls in those states. Also, 

without the CAIR SO2 program, emission requirements in many areas 

would revert to the comparatively less stringent requirements of 

the Title IV Acid Rain program. As a result, SO2 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 NOX. To do so with 
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respect to the 1997 and 2006 PM2.5 NAAQS, EPA analyzes the costs 

and associated air quality impacts of reductions in annual SO2

and annual NOX. 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 NOX SIP Call, the cost thresholds 

EPA uses in this proposed approach are informed by air quality 

considerations and applied on a state specific basis. EPA first 

develops state specific costs curves showing what level of 

emission reductions could be achieved at different cost levels 

in 2012 and 2014. EPA then uses a simplified air quality 

assessment tool to examine the impact of the reductions at 

specific cost levels, on downwind nonattainment and maintenance 
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sites. This approach allows EPA to identify specific cost 

breakpoints based on air quality considerations such as being a 

cost at which the air quality assessment analysis projects large 

numbers of downwind sites maintenance and nonattainment problems 

would be resolved or cost criteria, such as being a cost where 

large emission reductions occur because a particular technology 

is widely implemented at that cost. EPA then evaluated the 

reasonableness of the cost breakpoints using a number of 

criteria to determine which of the breakpoints appropriately 

represented a cost threshold with which to define significant 

contribution. 

 These thresholds are then applied on a state-specific 

basis to quantify each individual state’s significant

contribution. 

The remainder of this section provides further detail on the 

specific methodology developed by EPA and the application of 

this methodology to identify emissions that significantly 

contribute to or interfere with maintenance of the 1997 ozone 

NAAQS and the 1997 and 2006 PM2.5 NAAQS.

B. Overview of Approach to Identify Contributing Upwind States 

This section describes EPA’s proposal to require reductions 

in upwind emissions of SO2 and NOX to address PM2.5 transport and 

to require reductions in upwind emissions of NOX to address 

ozone-related transport. In addition, this section provides an 
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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 PM2.5 or 8-hour 

ozone standards or interfere with maintenance of those 

standards, in downwind states. 

The EPA assessed individual upwind states’ 2012 projected 

ambient impacts on downwind nonattainment and maintenance 

receptors for a 37-state region in the Eastern U.S., and 

established threshold values for PM2.5 and ozone to identify 

those states whose impact does not constitute a significant 

contribution to air quality 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 PM2.5 and 8-hour ozone NAAQS in downwind 

areas. The EPA used air quality modeling of emissions in each 

state to estimate the ambient impacts. The air quality modeling 

platform and approach to quantifying interstate contributions to 

PM2.5 and ozone are discussed in section IV.C. 

As noted previously, EPA considers that the maintenance 

concept has two components: year-to-year variability in 

emissions and air quality, and continued maintenance of the air 

quality standard over time. The way that EPA defined 

maintenance based on year-to-year variability is discussed in 
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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 supporting information 

in docket.)

1. Background

a. For the CAIR, how did EPA determine which pollutants were 

necessary to control to address interstate transport for PM2.5?

Section II of the January 2004 CAIR proposal summarized key 

scientific and technical aspects of the occurrence, formation, 

and origins of PM2.5, as well as findings and observations 

relevant to formulating control approaches for reducing the 

contribution of transport to fine particle problems (69 FR 4575-

87). Key concepts and provisional conclusions drawn from this 

discussion were summarized as follows in the preamble to the 

final CAIR: 

(1) Fine particles (measured as PM2.5 for the NAAQS) consist 

of a diverse mixture of substances that vary in size, chemical 

composition, and source. The PM2.5 includes both “primary” 
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particles that are emitted directly to the atmosphere as 

particles, and “secondary” particles that form in the atmosphere 

through chemical reactions from gaseous precursors. The major 

components of fine particles in the Eastern U.S. can be grouped 

into five components: carbonaceous material (including both 

primary and secondary organic carbon and black carbon), 

sulfates, nitrates, ammonium, and crustal material, which 

includes suspended dust as well as some other directly emitted 

materials. The major gaseous precursors of PM2.5 include SO2, 

NOX, NH3, 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 PM2.5, while crustal 

material tends to be only a small fraction. 

(3) Atmospheric interactions among particulate ammonium 

sulfates and nitrates and gas phase nitric acid and ammonia vary 

with temperature, humidity, and location. Both ambient 

observations and modeling simulations suggest that regional SO2

reductions are effective at reducing sulfate and associated 

ammonium, and, therefore, PM2.5. Under certain conditions 

reductions in particulate ammonium sulfates can release ammonia 

as a gas, which then reacts with gaseous nitric acid to form 

nitrate particles, a phenomenon called “nitrate replacement.” 
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In such conditions SO2 reductions would be less effective in 

reducing PM2.5, unless accompanied by reductions in NOX 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 NOX or ammonia control varies with 

atmospheric conditions; the highest particulate nitrate 

concentrations in the East tend to occur in cooler months and 

regions. At present, our knowledge about sources, emissions, 

control approaches, and costs is greater for NOX than for 

ammonia. Measures to reduce NOX from stationary and mobile 

sources have been implemented for more than 20 years. From a 

chemical perspective, as NOX reductions accumulate relative to 

ammonia, the atmospheric chemical system would move towards an 

equilibrium in which ammonium nitrate reductions become more 

responsive to further NOX 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 
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summarized in the CAIR proposal, EPA concluded that it was both 

appropriate and necessary to focus on control of SO2 and NOX

emissions as the most effective approach to reducing the 

contribution of interstate transport to PM2.5. 

For the CAIR, the EPA did not include emissions controls 

that affect other components of PM2.5, noting that “current 

information relating to sources and controls for other 

components identified in transported PM2.5 (carbonaceous 

particles, ammonium, and crustal materials) does not, at this 

time, provide an adequate basis for regulating the regional 

transport of emissions responsible for these PM2.5 components.” 

(69 FR 4582). For all of these components, the lack of 

knowledge of and ability to quantify 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 NOX (mainly NO and NO2). The term “VOC” includes many 
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classes of compounds that possess a wide range of chemical 

properties and atmospheric lifetimes, which helps 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 NOX and VOC are summarized in 

section IV of the proposal notice and EPA websites (e.g., 

http://www.w.gov/ttn/chief.) The relative importance of NOX and 

VOC in ozone formation and control varies with local- and timespecific factors, including the relative amounts of VOC and NOX

present. In rural areas with high concentrations of VOC from 

biogenic sources, ozone formation and control is governed by NOX. 

In some urban core situations, NOX 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-
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made and biogenic organics and can indirectly increase NOX as 

well (e.g., increased electricity generation for air 

conditioning). Summertime conditions also bring increased 

episodes of large-scale stagnation, which promote the build-up 

of direct emissions and pollutants formed through atmospheric 

reactions over large regions. Authoritative assessments of 

ozone control approaches have concluded that, for reducing 

regional scale ozone transport, a NOX 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., 1000s 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 NOX SIP Call reductions can be found on EPA’s website 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 transport 

made in great depth by the OTAG in the mid-1990s. As indicated 

in the NOX SIP call proposal, the OTAG Regional and Urban Scale 
125

Modeling and Air Quality Analysis Work Groups concluded that 

regional NOX emissions reductions are effective in producing 

ozone benefits; the more NOX 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 NOX

transport. Information on these analyses can be found at EPA’s 

website at: 

http://www.epa.gov/ttn/ecas/regdata/RIAs/452_R_08_003.pdf.

For addressing interstate ozone transport in the CAIR, EPA 

addressed NOX 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 
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change, due to the upwind state’s NOX and SO2 emissions, in 

annual19 PM2.5 concentration in the downwind nonattainment area 

that receives the largest ambient impact. The EPA proposed this 

metric in the form of a range of alternatives for a “bright 

line,” that is, air quality impacts at or greater than the 

chosen threshold level indicated that the upwind state’s 

emissions do contribute significantly (depending on cost 

considerations), and that air quality impacts below the 

threshold indicate that the upwind state’s emissions do not 

contribute significantly to nonattainment. 

This metric addresses how much each state contributes to a 

downwind neighbor. EPA does not believe that a particular 

upwind state must contribute to multiple downwind receptors to 

be required to make emissions reductions under CAA section 

110(a)(2)(D). Under this provision, an upwind state must 

include in the SIP adequate provisions that prohibit that 

state’s emissions that “contribute significantly to 

nonattainment in ... any other state....” (Emphasis added.) Our 

interpretation of this provision is that the emphasized terms 

make clear that the upwind state’s emissions must be controlled 

as long as they contribute significantly to a single 

nonattainment area.

 

19 For the CAIR, 24-hour PM2.5 was not at issue because there were 

little or no exceedances of the then-existing 65 μg/m3 24-hour 

standard
127

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 SO2 and NOX

emissions, rather than treating them separately. We believed 

this approach was consistent with the chemical interactions in 

the atmosphere of SO2 and NOX in forming PM2.5. The contributions 

of SO2 and NOX emissions are generally not additive, but rather 

are interrelated due to complex chemical reactions. 

In the CAIR proposal, EPA proposed to establish a statelevel annual average PM2.5 contribution threshold from 

anthropogenic SO2 and NOX emissions that was a small percentage 

of the annual air quality standard of 15.0 μg/m3. 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” PM2.5 transport shows that, in 

general, PM2.5 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 
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particular upwind states. In the NOX SIP Call rulemaking, we 

termed this pattern of contribution – which is also present for 

ozone nonattainment – “collective contribution.”

In the case of PM2.5, we have found collective contribution 

to be a pronounced feature of the PM2.5 transport problem, in part 

because the annual nature of the PM2.5 NAAQS means that 

throughout the entire year and across a range of wind patterns –

rather than during just one season of the year or on only the 

few worst days during the year which may share a prevailing wind 

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 PM2.5

transport contribution threshold was appropriate. For the final 

CAIR EPA decided to apply a threshold of 0.20 μg/m3, such that 

any model 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 
129

followed the approach used in the NOX 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 NOX and VOC emissions on each downwind 

nonattainment areas. 

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:
130

• the magnitude of the contribution (actual amount of ozone 

contributed by emissions in the upwind state to nonattainment in 

the downwind area); 

• the frequency of the contribution (how often 

contributions above certain thresholds occur); and 

• the relative amount of the contribution ( the total ozone 

contributed by the upwind state compared to the total amount of 

nonattainment ozone in the downwind area).

2. Approach for Proposed Rule

a. Which pollutants do we propose to control? 

For the proposed rule, EPA believes that the conclusions 

and findings in the final CAIR regarding the nature of pollutant 

contributions are still appropriate. EPA proposes to continue 

to focus the PM2.5 transport requirements on SO2 and NOX

transport, and the ozone transport requirements on NOX.

EPA recognizes that, in some circumstances, the state’s NOX

contribution to PM2.5 in downwind states may be considerably 

smaller than the state’s SO2 contribution to PM2.5 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 NOX controls, within 

levels that could realistically be achieved, would result in a 

very small change in ambient PM2.5 levels. EPA considered 
131

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 SO2 emissions decrease without accompanying 

decreases in NOX. Third, EPA believes that there would be 

important disbenefits to relaxing annual NOX requirements in 

those states. If for those states, EPA were to relax the annual 

NOX requirements currently required for their contribution to 

PM2.5, annual NOX 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 PM2.5, 24-hour PM2.5, and 8-hour ozone. Each threshold is 

based on 1 percent of the NAAQS.

As we found at the time of the CAIR, EPA’s analysis of 

“base case” PM2.5 transport shows that, in general, PM2.5
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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 PM2.5 and ozone.

For annual PM2.5 for the final CAIR, as noted previously, 

EPA decided to use a single-digit value, 0.2 μg/m3, rather than 

the two-digit value in the proposed CAIR, 0.15 μg/m3. The 

rationale for the single digit value for the final rule was that 

a single digit is consistent with the EPA monitoring 

requirements in Part 50, Appendix N, section 4.3. The reporting 

requirements for annual PM2.5 require that: 

Annual PM2.5 standard design values shall be rounded to the 

nearest 0.1 μg/m3 (decimals 0.05 and greater are rounded up 

to the next 0.1, and any decimal lower than 0.05 is rounded 

down to the nearest 0.1).

Because the design value is to be reported only to the 

nearest 0.1 μg/m3, EPA deemed it preferable for the final CAIR 

to select the threshold value at the nearest 0.1 ug/m3 as well, 

and hence one percent of the 15 μg/m3, rounded to the nearest 

0.1 μg/m3 became 0.2 μg/m3. 
133

For the 24-hour standard of 35 μg/m3, we attempted to apply 

the same rationale for determining a single-digit air quality 

threshold. That is, we applied rounding conventions in Part 50, 

Appendix N to a value representing one percent of the NAAQS. 

The rounding requirements for the 24-hour standard are indicated 

in section 4.3 as follows:

24-hour PM2.5 standard design values shall be rounded to the 

nearest 1 μg/m3 (decimals 0.5 and greater are rounded up to 

the nearest whole number, and any decimal lower than 0.5 is 

rounded down to the nearest whole number).

One percent of the 24-hour standard is 0.35 μg/m3, and 

rounding to the nearest whole μg/m3 would yield an air quality 

threshold of zero. Thus applying the same rationale for the

final CAIR, there would be no air quality threshold for 24-hour 

PM2.5, which EPA believes to be counterintuitive and unworkable 

as an approach for assessing interstate contributions. 

For the proposed rule, EPA proposes to decouple the 

precision of the air quality thresholds with the monitoring 

reporting requirements, and to use 2-digit values representing 

one percent of the NAAQS, that is, 0.15 μg/m3 for the annual 

standard, and 0.35 μg/m3 for the 24-hour standard. EPA believes 

there are a number of 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 NAAAQS. For example, if EPA were to 
134

retain the CAIR approach for the annual standard, any future 

lowering of the PM2.5 NAAQS to below 15 μg/m3 would reduce the air 

quality threshold to 0.1 μg/m3. This would occur because any 

value less than 0.15 μg/m3 (e.g., 0.14 μg/m3) would be rounded 

down to 0.1 μg/m3. EPA finds it within its discretion to adjust 

its approach to account for the additional considerations that 

were not in existence at the time of the final CAIR. 

For the proposal, EPA is proposing to take a more 

straightforward approach to air quality thresholds for ozone 

than the multi-factor approach we used for the NOX 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 PM2.5, and because it provides for a consistent 

approach that takes into account, and is applicable to, any 

future ozone standards below 0.08 ppm.
135

EPA seeks comment on the pollutants and air quality 

thresholds used for identifying states to be included under the 

proposed rule.

C. Air Quality Modeling Approach and Results

1. What 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 PM2.5, 

24-hour PM2.5, and/or 8-hour ozone for the analytic years chosen 

for this proposal, (2) quantify the impacts (i.e., air quality 

contributions) of SO2 and NOX emissions from upwind states on 

downwind annual average and 24-hour PM2.5 concentrations at 

monitoring sites projected to be nonattainment or have 

maintenance problems in 2012 for the 1997 annual and 2006 24-

hour PM2.5 NAAQS, respectively, (3) quantify the impacts of NOX

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 
136

these models, the evaluation of the air quality model compared 

to measured concentrations, and the procedures for projecting 

ozone and PM2.5 concentrations for future year scenarios. We 

also provide in this section the interstate contributions for 

annual average and 24-hour PM2.5, and 8-hour ozone. The Air 

Quality Modeling Technical Support Document (AQMTSD) contains 

more detailed information on the air quality modeling aspects of 

this rule.

To support the proposal, air quality modeling was performed 

for four emissions 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 PM2.5 and 8-hour ozone. The 2014 base 

case and 2014 control case modeling were used to quantify the 

benefits of this proposal.

For CAIR, EPA used two air quality models, the 

Comprehensive Air Quality Model with Extensions (CAMx), version 

3.1 for modeling ozone and the Community Multiscale Air Quality 
137

Model (CMAQ) version 4.3 for modeling PM2.5. Both CAMx and CMAQ 

are grid cell-based, multi-pollutant photochemical models that 

simulate the formation and fate of ozone and fine particles in 

the atmosphere. For the proposed rule EPA used CAMx version 520

to simulate ozone and PM2.5 concentrations for the 2005 base year 

and the 2012 and 2014 future year scenarios. The use of one 

model for both pollutants provides a more scientifically 

integrated “one atmosphere” approach versus using different 

models for ozone and PM2.5. In addition, using a single model 

rather than two models is computationally more efficient. The 

CAMx model applications were designed to cover States in the 

Central and Eastern U.S. using a horizontal resolution of 12 x 

12 km21. The modeling region (i.e., modeling domain) extends 

from Texas northward to North Dakota and eastward to the East 

Coast and includes 37 states and the District of 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 

 

20 Comprehensive Air Quality Model with Extensions Version 5 

User’s Guide. Environ International Corporation. Novato, CA. 

March 2009.

21 The 12 km domain was nested within a coarse grid, 36 x 36 km 

modeling domain which covers the lower 48 states and adjacent 

portions of Canada and Mexico. Predictions from this 

Continental U.S. (CONUS) domain were used to provide initial and 

boundary concentrations for simulations in the 12 km domain.
138

emissions from various sources and areas to ozone and PM2.5

component species in other downwind locations. The CAMx model 

was chosen for use in this rule because the source apportionment 

tools in this model have had extensive use and evaluation by 

states and industry. Also, the source apportionment tools in 

CAMx received favorable comments in a recent peer review22.

The 2005-based air quality modeling platform used for the 

proposal includes 2005 base year emissions and 2005 meteorology 

for modeling ozone and PM2.5 with CAMx. This platform provides 

an update to the now more historical data in the 2001-based 

platform used for CAIR that included 2001 emissions, 2001 

meteorology for modeling PM2.5, and 1995 meteorology for modeling 

ozone. In the remainder of this section we provide an overview 

of (1) the emissions and 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 PM2.5 and ozone, and (4) the predicted 

interstate contributions to downwind nonattainment and 

maintenance. We also identify which predicted interstate 

 

22 Arunachalam, S. Peer Review of Source Apportionment Tools in 

CAMx and CMAQ, EP-D-07-102. University of North Carolina, 

Institute for the Environment, August 2009.
139

contributions are at or above the air quality impact thresholds 

described 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 NOX, VOCs 

and PM2.5 were split into their components species using other 

data sources, to provide the modeling species needed by CAMx. 

Elevated point sources were 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 
140

3.1423,24. The same biogenic emissions data were used in all 

scenarios modeled. 

(1) Development of 2005 Base Year Emissions

Emissions inventory inputs representing the year 2005 were 

developed to provide a base year for forecasting future air 

quality, described in 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.

 

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 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.
141

The onroad and nonroad emissions were primarily based on 

the National Mobile Inventory Model (NMIM) monthly, county, 

process level emissions from the 2005 NEI v2. The 2005 onroad 

mobile emissions were augmented for onroad gasoline emissions 

sources with emissions based on a draft version of the Motor 

Vehicle Emissions Simulator (MOVES) for carbon monoxide (CO), 

NOX, VOC, PM2.5, and particulate matter less than ten microns 

(PM10). While these data were preliminary, they more closely 

reflect the PM2.5 emissions from the final release of MOVES 2010. 

To account for the temperature dependence of PM2.5, MOVES-based 

temperature adjustment factors were applied to gridded, hourly 

emissions using gridded, hourly meteorology. Additional 

information on this approach is available in the EITSD.

The annual NOX and SO2 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 SO2 and NOX were augmented by using hourly CEM 

data to develop a temporal allocation approach of the 2005 NEI 

v2 emissions. The annual emissions themselves were unchanged, 

and match closely with data from the CEM program except where 

states have provided data for partial CEM and non-CEM units. 
142

The 2005 EGUs were identified as all units in 2005 that map to 

the units modeled by the version of the Integrated Planning 

Model (IPM) used for this proposal, and include records both 

with and without data submitted to the CEM program. Temporal 

profiles were used instead of the actual 2005 CEM data so that 

the temporal allocation approach could be consistent in the 

future year modeling.

For the 2005 base year, the annual EGU NEI emissions were 

allocated to hourly emissions values needed for modeling based 

on the 2004, 2005, and 2006 CEM data. The NOX CEM data were used 

to create NOX -specific profiles, the SO2 data were used to 

create SO2-specific profiles, and the heat input data were used 

to allocate all other pollutants. The 3 years of data were used 

for monthly and hourly profiles by state, while the 2005 data 

were used for the daily allocation from month, to preserve an 

appropriate level of temporal variability.

Other significant augmentations were also made to the 2005 

NEI and include the following. The nonpoint inventory was 

augmented with oil and gas exploration inventory25 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 

 

25 The oil and gas exploration inventory was provided by the 

Western Regional Air Partnership.
143

emissions were augmented with gridded 2005 emissions from the 

previous modeling efforts for the rule called “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 were replaced with 

average-year county-based 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 SO2 and NOX

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.
144

Table IV.C-1. 2005 Base Case SO2 Emissions (Tons/Year) for 

Eastern States by Sector.

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Alabama 460,123 70,346 52,325 6,397 3,199 983 593,372

Arkansas 66,384 13,066 27,260 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

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

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 9,909,693 1,913,263 1,109,467 591,832 120,848 18,876 13,663,979
145

Table IV.C-2. 2005 Base Case NOX Emissions (Tons/Year) for 

Eastern States by Sector.

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Alabama 133,051 74,830 32,024 61,623 142,221 3,814 447,562

Arkansas 35,407 37,478 21,453 63,493 81,014 2,654 241,499

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

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

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

Grand Total 3,136,980 1,857,64

6

1,207,152 3,591,79

1

5,641,640 79,222 15,514,431

(2) Development of Future Year Emissions
146

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 PM2.5 NAAQS and 

the ozone NAAQS are not included in the future base case 

projections. The future base case scenarios do reflect 

projected economic changes and fuel usage for EGU and mobile 

sectors, as described in the EITSD.

Tables IV.C-3 through IV.C-6 later provide 2012 and 2014 

summaries of emissions data for 2012 and 2014 modeling for all 

sectors for SO2 and NOX 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.

Table IV.C-3. 2012 Base Case SO2 Emissions (Tons/Year) for 

Eastern States by Sector.

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Alabama 335,734 70,346 52,315 2,333 585 983 462,297

Arkansas 85,068 13,054 27,257 818 336 728 127,259

Connecticut 5,493 1,831 18,443 1,292 330 4 27,392

Delaware 7,841 10,974 5,858 14,193 98 6 38,970

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
147

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Illinois 724,657 133,201 5,384 1,960 1,174 20 866,396

Indiana 829,988 95,201 59,767 871 775 24 986,626

Iowa 169,039 61,242 19,821 482 346 25 250,954

Kansas 59,567 13,048 36,376 518 302 103 109,915

Kentucky 718,980 25,813 34,214 1,368 510 364 781,249

Louisiana 100,239 159,722 2,373 78,051 455 892 341,731

Maine 15,759 18,519 9,950 3,926 156 150 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 902 5,381 6 94 49 6,432

Virginia 145,452 69,166 32,904 15,158 883 399 263,963

West Virginia 588,392 41,817 14,583 443 197 215 645,646

Wisconsin 107,365 66,452 6,370 928 646 70 181,830

Grand Total 9,243,362 1,802,927 1,116,694 451,705 24,595 19,345 12,658,628

Table IV.C-4. 2012 Base Case NOX Emissions (Tons/Year) for 

Eastern States by Sector.

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

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
148

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Indiana 203,107 73,651 30,125 83,760 114,396 88 505,127

Iowa 66,316 39,301 15,064 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 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

Table IV.C-5. 2014 Base Case SO2 Emissions (Tons/Year) for 

Eastern States by Sector.

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Alabama 322,130 69,150 52,313 1,873 605 983 447,053

Arkansas 88,187 13,055 27,256 142 347 728 129,714

Connecticut 5,512 1,834 18,440 1,294 340 4 27,423

Delaware 7,806 10,974 5,857 14,891 101 6 39,635

District of 

Columbia 0 686 1,559 4 42 0 2,291

Florida 192,903 57,521 70,480 108,579 2,159 7,018 438,658

Georgia 173,210 56,014 56,813 8,263 1,307 2,010 297,618

Illinois 200,475 133,109 5,381 390 1,221 20 340,596
149

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Indiana 804,294 95,037 59,764 193 810 24 960,123

Iowa 163,966 60,195 19,817 85 360 25 244,448

Kansas 65,125 13,048 36,375 54 313 103 115,018

Kentucky 739,592 23,804 34,210 258 528 364 798,755

Louisiana 94,824 151,216 2,372 78,097 470 892 327,871

Maine 11,650 18,520 9,945 4,215 160 150 44,640

Maryland 42,635 34,994 40,851 16,966 631 32 136,109

Massachusetts 16,299 19,624 25,237 32,043 594 93 93,890

Michigan 275,637 76,437 42,066 7,536 1,107 91 402,874

Minnesota 61,447 25,112 14,728 468 618 631 103,005

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

Rhode Island 0 2,745 3,364 3,128 85 1 9,323

South 

Carolina 156,096 31,453 30,002 24,380 551 646 243,129

South Dakota 13,459 1,699 10,298 22 94 498 26,070

Tennessee 600,066 77,605 32,696 173 829 277 711,647

Texas 373,950 155,720 109,194 36,109 2,511 1,178 678,662

Vermont 903 5,380 7 101 49 6,439

Virginia 135,741 69,177 32,899 15,624 918 399 254,758

West Virginia 496,307 41,817 14,581 96 201 215 553,218

Wisconsin 117,253 66,456 6,370 638 675 70 191,461

Grand Total 8,209,536 1,778,244 1,116,600 453,742 25,516 19,345 11,602,982

Table IV.C-6. 2014 Base Case NOX Emissions (Tons/Year) for 

Eastern States by Sector.

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Alabama 118,420 74,622 31,939 45,932 67,011 3,814 341,738

Arkansas 44,792 37,491 21,422 44,299 38,965 2,654 189,623

Connecticut 2,821 5,854 12,451 14,410 31,534 14 67,084

Delaware 4,513 5,567 3,245 15,270 8,736 23 37,353

District of 

Columbia 1 501 1,738 2,398 3,929 0 8,568

Florida 180,801 55,343 29,457 278,920 225,478 25,600 795,599

Georgia 48,091 53,557 38,797 71,011 130,240 7,955 349,650

Illinois 80,228 93,059 47,540 151,373 131,403 71 503,676
150

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total

Indiana 200,899 73,523 30,107 76,024 94,217 88 474,858

Iowa 68,146 38,831 15,038 65,751 48,836 90 236,692

Kansas 78,920 70,730 42,238 61,613 35,950 378 289,829

Kentucky 148,509 34,979 17,413 65,805 57,759 1,326 325,791

Louisiana 45,457 161,766 27,515 274,697 52,360 3,254 565,049

Maine 2,535 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 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 PM2.5 were 

obtained from version 3.02 EISA of the IPM 

(http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html). The 
151

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 SO2 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 Electric Generation 

Modeling Technical Support Document (EGMTSD). Also note that as 

explained in section IV.A.3, the baseline used in this analysis 

assumes no CAIR. If EPA’s base case analysis were to assume 

that reductions from CAIR would continue 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).
152

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, NOX, 

VOC, PM2.5, and PM10. The same MOVES-based PM2.5 temperature 

adjustment factors were also applied as in 2005.

Nonroad mobile emissions were created only with NMIM using 

a consistent approach as was used for 2005, but emissions were 
153

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 NOX, 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.
154

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 NOX 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 
155

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 
156

Model. This model, commonly referred to as MM5, is a limitedarea, nonhydrostatic, terrain-following system that solves for 

the full set of physical and thermodynamic equations which 

govern atmospheric motions.26 The meteorological outputs from 

MM5 were processed to create model-ready inputs for CMAQ using 

the MM5-to-CAMx preprocessor (ref CAMx user’s guide).

The 2005 MM5 meteorological predictions for selected 

variables were compared to measurements as part of several 

performance evaluations of the 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 modelestimated synoptic patterns against observed patterns from 

historical weather chart archives. Additionally, the 

evaluations compared spatial patterns of monthly average 

rainfall and monthly maximum planetary boundary layer (PBL) 

heights. The operational evaluation included statistical 

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 

 

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.
157

portion of the evaluation, five meteorological parameters were 

investigated: temperature, humidity, shortwave downward 

radiation, wind speed, and wind direction. The three individual 

MM5 evaluations are described elsewhere.27,28,29 It was ultimately 

determined that the bias and error values associated with the 

2005 meteorological data were generally within the range of past 

meteorological modeling results that have been used for air 

quality applications. Additional details on the meteorological 

inputs can be found in the AQMTSD.

As noted previously, the CAMx simulations for this 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 

 

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.
158

modeling. Pollutant concentrations at the boundaries of the

coarse scale modeling domain were obtained from a threedimensional global atmospheric chemistry model, the GEOSChem30

model (standard version 7-04-1131). The global GEOSChem model 

simulates atmospheric chemical and physical processes driven by 

assimilated meteorological observations from the NASA’s Goddard 

Earth Observing System (GEOS). This model was run for 2005 with 

a grid resolution of 2.0 degree x 2.5 degree (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 PM2.5

The 2005 base year model predictions for ozone and fine 

particulate sulfate, nitrate, organic carbon, elemental carbon, 

and crustal material were compared to measured concentrations in 

order to evaluate the performance of the modeling platform for 

replicating observed concentrations. This evaluation was 

comprised principally of statistical assessments of paired 

 

30 Yantosca, B., 2004. GEOS-CHEMv7-01-02 User’s Guide, 

Atmospheric Chemistry Modeling Group, Harvard University, 

Cambridge, MA, October 15, 2004.

31 Henze, D.K., J.H. Seinfeld, N.L. Ng, J.H. Kroll, T-M. Fu, D.J. 

Jacob, C.L. Heald, 2008. Global modeling of secondary organic 

aerosol formation from aromatic hydrocarbons: high- vs. lowyield pathways. Atmos. Chem. Phys., 8, 2405-2420.
159

modeled and observed data. Details on the evaluation 

methodology and the calculation of performance statistics are 

provided in the AQMTSD. The results indicate that, overall, the 

predicted patterns and day-to-day variations in regional ozone 

levels are similar to what was observed with measured data. The 

normalized mean bias for 8-hour daily maximum ozone 

concentrations was 17.6 percent and the normalized mean error 

was 24.8 percent for the months of June through August 2005, 

based on an aggregate of all observed-predicted pairs within the 

12 km modeling domain. The two PM2.5 species that are most 

relevant for this proposal are sulfate and nitrate. For the 

summer months of June though August, when observed sulfate 

concentrations are highest in the East, the model predictions of 

24-hour average sulfate were lower than the corresponding 

measured values by 7 percent at urban sites and by 8 to 10 

percent at rural sites in the IMPROVE32 and CASTNET33 monitoring 

networks, respectively. For the winter months of December 

through February, when observed nitrate concentrations are 

highest in the East, the model predictions of 24-hour average 

 

32 Interagency Monitoring of PROtected Visual Environments 

(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.
160

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 PM2.5 component species are 

provided in the AQMTSD.

2. How did EPA project future nonattainment and maintenance for 

annual PM2.5, 25-Hour PM2.5, and 8-hour ozone? 

In this section we describe the approach for projecting 

future concentrations of ozone and PM2.5 to identify locations 

that are expected to be nonattainment or have a maintenance 

problem in 2012. The nonattainment and maintenance locations 

are based on projections of future air quality at existing ozone 

and PM2.5 monitoring sites. These sites are used as the 

“receptors” for quantifying the contributions of emissions in 

upwind states to nonattainment and maintenance in downwind 

locations. For 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 in the 

relative (percent) change in model predictions for each 

location.

a. How did EPA process ambient ozone and PM2.5 data for the 

purpose of projecting future year concentrations? 
161

In this analysis we use measurements of ambient ozone and 

PM2.5 data that come from monitoring networks consisting of more 

than one thousand ozone monitors and one thousand PM2.5 monitors 

located across the country. The monitors are sited according to 

the spatial and temporal nature of ozone and PM2.5, and to best

represent the actual air quality in the United States. The 

ambient data used in this analysis were obtained from EPA’s Air 

Quality System (AQS).

In order to use the ambient data, the raw measurements must 

be processed into a form pertinent for useful 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 PM2.5 ambient data were processed consistent with the 

formats associated with the NAAQS for PM2.5. The resulting 

estimates are used to indicate the level of air quality relative 

to the NAAQS. For PM2.5, we evaluated concentrations of both the 
162

annual average PM2.5 NAAQS and the 24-hour PM2.5 NAAQS. The 

annual PM2.5 standard is met when the 3-year average of the 

annual mean concentration is 15.0 μg/m3 or less. The 3-year 

average annual mean concentration is computed at each site by 

averaging the daily Federal Reference Method (FRM) samples by 

quarter, averaging these quarterly averages to obtain an annual 

average, and then averaging the three annual averages. 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 PM2.5 concentration is 35 μg/m3 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 PM2.5 design values involved the projection of an 

average of up to 3 design value periods which include the years 

2003-2007 (design values for 2003-2005, 2004-2006, and 2005-

2007). The average of the 3 design values creates a “5-year 

weighted average” value. The 5-year weighted average values 

were then projected to the future years that were analyzed for 

this proposed rule. The 2003–2005, 2004-2006, and 2005-2007 
163

design values are accessible at 

www.epa.gov/airtrends/values.html. 

The procedures for projecting annual average PM2.5 and 8-

hour ozone were very similar to the methodology used in CAIR. 

However, the CAIR final rule was promulgated before the most 

recent version of the attainment demonstration modeling guidance 

was finalized34. The procedures for the proposed rule conform to 

the methodology contained in the final modeling guidance. In 

the CAIR analysis, EPA did not project 24-hour PM2.5 design 

values35. The analysis for this proposed rule, in contrast, uses 

the 24-hour PM2.5 methodology outlined in the modeling guidance.

b. Projection of Future Annual and 24-Hour PM2.5 Nonattainment 

and Maintenance

Annual PM2.5 modeling was performed for the 2005 base year 

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 

 

34 U.S. EPA, 2007: Guidance on the Use of Models and Other 

Analyses for Demonstrating Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze; Office of Air Quality Planning 

and Standards, Research Triangle Park, NC.

35 CAIR was promulgated in 2005 before the 35 ug/m3 PM2.5 NAAQS 

was finalized in 2006. Since there were no violations in the 

eastern United States (base or future year) of the 1997 65 ug/m3 

NAAQS, it was not necessary to project 24 PM2.5 values as part of 

the modeling for CAIR. 
164

PM2.5 standards in 2012. We refer to these areas as 

nonattainment sites and maintenance sites respectively. 

In general, the projection methodology involves using the 

model in a relative sense to estimate the change in PM2.5 between 

2005 and the future 2012 base case as recommended in the 

modeling guidance. Rather than use the absolute model-predicted 

future year ozone and PM2.5 concentrations, the base year and 

future year predictions are used to calculate a (relative) 

percent change in ozone and PM2.5 concentrations. For a 

particular location, the percent change in modeled concentration 

is multiplied by the corresponding observed base period ambient 

concentration to estimate the future year design value for that 

location. The use of observed ambient data as part of the 

calculation helps to constrain the future year design value 

predictions, even if the absolute model concentrations are overpredicted or under-predicted. 

Concentrations of PM2.5 in 2012 were estimated by applying 

the 2005 to 2012 relative change in model-predicted PM2.5 species 

to the (2003-2007) PM2.5 design values. The choice of base 

period design values is consistent with EPA’s modeling guidance 

which recommends using the average of the three design value 

periods centered about the emissions projection year. Since 

2005 was the base emissions year, we used the design value for 

2003-2005, 2004-2006, and 2005-2007 to represent the base period 
165

PM2.5 concentrations. For each FRM PM2.5 monitoring site, all 

valid design values (up to 3) from this period were averaged 

together. Since 2005 is included in all three design value 

periods, this has the effect of creating a 5-year weighted 

average, where the middle year is weighted 3 times, the 2nd and 

4

th 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 PM2.5

 

36 If there is only one complete design value, then the 

nonattainment and maintenance design values are the same. 
166

NAAQS, and 736 sites which met this criteria for the 24-hour 

NAAQS37.

EPA followed the procedures recommended in the modeling 

guidance for projecting PM2.5 by projecting individual PM2.5

component species and then summing these to calculate the 

concentration of total PM2.5. The model predictions are used in 

a relative sense to estimate changes expected to occur in each 

of the major PM2.5 species. The PM2.5 species are sulfate, 

nitrate, ammonium, particle bound water, elemental carbon, salt, 

other primary PM2.5, and organic aerosol mass by difference. 

Organic aerosol mass by difference is defined as the difference 

between FRM PM2.5 and the sum of the other components. The 

procedure for calculating future year PM2.5 design values is 

called the SMAT. The SMAT approach is codified in a software 

tool available from EPA called MATS. The software (including 

documentation) is available at:

http://www.epa.gov/scram001/modelingapps_mats.htm.

(1) Methodology for Projecting Future Annual PM2.5 Nonattainment 

and Maintenance

 

37 Design values were only used if they were deemed to be 

officially complete based on CFR 40 Part 50 Appendix N. The 

completeness criteria for the annual and 24-hour PM2.5 NAAQS are 

different. Therefore, there are fewer complete sites for the 

annual NAAQS.

 
167

The following is a brief summary of the future year annual 

PM2.5 calculations. Additional details are provided in the 

modeling guidance, MATS documentation, and the AQMTSD.

We are 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 PM2.5 speciation is needed for the location 

of each FRM monitoring site. Since co-located PM2.5 speciation 

data are only available at ~15 percent of FRM monitoring sites, 

spatial interpolation techniques are used to calculate species 

concentrations for each FRM monitoring site. Speciation data 

from the IMPROVE and Speciation Trends Network (STN) were 

interpolated to each FRM monitor location using the Voronoi 

Neighbor Averaging (VNA) technique (using MATS). Additional 

information on the VNA interpolation techniques and data 

handling procedures can be found in 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 PM2.5 (i.e., sulfate, nitrate, 

ammonium, elemental carbon, organic carbon mass, particle bound 

water, salt, and blank mass). This is done by multiplying the 

monitored quarterly mean concentration of FRM-derived total PM2.5
168

by the monitored fractional composition of PM2.5 species for each 

quarter averaged over 3 years38 (e.g., 20 percent sulfate 

fraction multiplied by 15 μg/m3 PM2.5 equals 3 μg/m3 sulfate). 

Step 2: For each quarter, calculate the ratio of future 

year to base year model predictions for each of the component 

species39. The result is a set of species-specific relative 

response factors (RRF) (e.g., assume that the model-predicted 

2005 base year sulfate for a particular location is 10.0 μg/m3

and the 2012 future concentration is 8.0 μg/m3, then RRF for 

sulfate is 0.8). The RRFs are calculated based on the modeled 

concentrations averaged over the nine grid cells40 centered at 

the location of the monitor.

Step 3: For each quarter and each of the species, multiply 

the base year quarterly mean component concentration (Step 1) by 

the species-specific RRF obtained in Step 2. This results in an 

estimated future year quarterly mean concentration for each 

 

38 For this analysis, species fractions were calculated using an 

average of FRM and speciation data for the 2004-2006 time 

period. This was deemed to be representative of the 2005 base 

year. 

39 We did not explicitly model salt and therefore the salt 

concentration was held constant from the base to future. Also, 

blank mass was assumed to be a constant mass of 0.5 ug/m3 in 

both the base and future years. 

40 The modeling guidance recommends calculating annual PM2.5 RRFs 

using a 3 X 3 grid cell array (9 grid cells) for a model 

resolution of 12km.
169

species (e.g., 3 μg/m3 sulfate multiplied by 0.8 equals a future 

sulfate concentration of 2.4 μg/m3).

Step 4: Average the four quarterly mean future 

concentrations to obtain the future year annual design value 

concentration for each of the component species. Sum the 

species concentrations to obtain the future year annual average 

design value for PM2.5.

Step 5: Calculate the maximum future design value by 

processing each of the three base design value periods (2003-

2005, 2004-2006, and 2005-2007) separately. The highest of the 

three future values is the maximum design value. The maximum 

design values are used to determine future year maintenance 

sites.

The preceding procedures for determining future year PM2.5

concentrations were applied for each FRM site. The calculated 

annual PM2.5 design values are truncated (i.e., discarded) after 

the second decimal place41. This is consistent with the 

truncation and rounding procedures for the annual PM2.5 NAAQS. 

Any value that is greater than or equal to 15.05 μg/m3 is rounded 

to 15.1 μg/m3 and is considered to be violating the NAAQS. Thus, 

sites with future year annual PM2.5 design values of 15.05 μg/m3

or greater, based on the projection of 5-year weighted average 

 

41 For example, a calculated annual average concentration of 

14.94753... becomes 14.94 when digits beyond two places to the 

right are truncated. 
170

concentrations, are predicted to be nonattainment sites. Sites 

with future year maximum design values of 15.05 μg/m3 or greater 

are predicted to be 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 PM2.5 NAAQS in the 2012 base case are 

the nonattainment/maintenance receptors used for assessing the 

contribution of emissions in upwind states to downwind 

nonattainment and maintenance of the annual PM2.5 NAAQS as part 

of this proposal.

Table IV.C-7 contains the 2003-2007 base case period 

average and maximum annual PM2.5 design values and the 

corresponding 2012 base case average and maximum design values 

for sites projected to be nonattainment of the annual PM2.5 NAAQS 

in 2012. Table IV.C-8 contains this same information for 

projected 2012 maintenance sites.
171

Table IV.C-7. Average and Maximum 2003-2007 and 2012 Base Case 

Annual PM2.5 Design Values (μg/m3) at Projected Nonattainment 

Sites.

Monitor ID State County Average

Design 

Value 

2003-2007

Maximum 

Design 

Value 

2003-

2007

Average 

Design 

Value 

2012

Maximum 

Design 

Value 

2012

10730023 Alabama Jefferson 18.48 18.67 17.15 17.33

10732003 Alabama Jefferson 17.07 17.45 15.99 16.35

130210007 Georgia Bibb 16.47 16.78 15.33 15.62

130630091 Georgia Clayton 16.47 16.71 15.07 15.29

131210039 Georgia Fulton 17.43 17.47 16.01 16.04

170310052 Illinois Cook 15.75 16.02 15.16 15.43

171191007 Illinois Madison 16.72 17.01 16.56 16.85

171630010 Illinois Saint 

Clair

15.58 15.74 15.48 15.63

180190006 Indiana Clark 16.40 16.60 15.96 16.16

180372001 Indiana Dubois 15.18 15.68 15.07 15.57

180970078 Indiana Marion 15.26 15.43 15.18 15.36

180970081 Indiana Marion 16.05 16.36 15.93 16.25

180970083 Indiana Marion 15.90 16.27 15.77 16.15

211110043 Kentucky Jefferson 15.53 15.75 15.19 15.41

261630015 Michigan Wayne 15.88 16.40 15.05 15.55

261630033 Michigan Wayne 17.50 18.16 16.57 17.19

390170016 Ohio Butler 15.74 16.11 15.25 15.61

390350038 Ohio Cuyahoga 17.37 18.1 16.26 16.95

390350045 Ohio Cuyahoga 16.47 16.98 15.42 15.91

390350060 Ohio Cuyahoga 17.11 17.66 16.02 16.55

390610014 Ohio Hamilton 17.29 17.53 16.69 16.93

390610042 Ohio Hamilton 16.85 17.25 16.33 16.71

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 Pennsylv

ania

Allegheny 20.31 20.75 18.90 19.31

420031301 Pennsylv

ania

Allegheny 16.26 16.57 15.13 15.42

420070014 Pennsylv

ania

Beaver 16.38 16.45 15.23 15.30

420710007 Pennsylv

ania

Lancaster 16.55 17.46 15.19 16.01

421330008 Pennsylv

ania

York 16.52 17.25 15.25 15.94

540110006 West 

Virginia

Cabell 16.30 16.57 15.25 15.50

540391005 West 

Virginia

Kanawha 16.52 16.59 15.28 15.34
172

Table IV.C-8. Average and Maximum 2003-2007 and 2012 Base Case 

Annual PM2.5 Design Values (μg/m3) at Projected Maintenance-Only 

Sites.

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 Montgomer

y

15.54 15.92 15.01 15.37

391510017 Ohio Stark 16.15 16.59 14.99 15.40

420110011 Pennsylv

ania

Berks 15.82 16.19 14.77 15.11

482011035 Texas Harris 15.42 15.84 14.74 15.14

540030003 West 

Virginia

Berkeley 15.93 16.19 14.95 15.20

540090005 West 

Virginia

Brooke 16.52 16.80 14.95 15.22

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 PM2.5 Nonattainment 

and Maintenance

The following is a brief summary of the procedures used for 

calculating future year 24-hour PM2.5 design values. Additional 

details are provided in the modeling guidance, MATS 

documentation, and the AQMTSD. Similar to the annual PM2.5

calculations, we are using the 2003-2007 base period FRM data 
173

for projecting future year design values. The 24-hour PM2.5

calculations are computationally similar to the annual average 

calculations. The main difference is that the base period 24-

hour 98th percentile PM2.5 concentrations are projected to the 

future year, instead of the annual average concentrations. 

Also, the PM2.5 species fractions and relative response factors 

are calculated from observed and modeled high concentration 

days, instead of quarterly average data. 

Both the annual PM2.5 and 24-hour PM2.5 calculations are 

performed on a calendar quarter basis. Since all years and 

quarters are averaged together in the annual PM2.5 calculations, 

the individual years can be averaged together early in the 

calculations. However, in the 24-hour PM2.5 calculations, only 

the high 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.

The following are the steps followed for calculating the 

2012 base case 24-hour PM2.5 design values:

Step 1: At each FRM monitoring site, we identify the 

maximum 24-hour PM2.5 concentration in each quarter that is less 

than or equal to the 98th percentile value over the entire year. 
174

This results in a data set for each year (for up to 5 years) for 

each site containing one quarter with the observed 98th 

percentile value and three quarters with the maximum highest 

values from each quarter that are less than or equal to the 98th 

percentile value for the year. All 20 quarters (i.e., 4 

quarters in each of 5 years) of data are carried through the 

calculations until the high future year quarter value is 

identified in step 5. 

Step 2: In this step we calculate quarterly ambient 

concentrations on “high”42 days for each of the major component 

species of PM2.5 (sulfate, nitrate, ammonium, elemental carbon, 

organic carbon mass, particle bound water, salt and blank mass). 

This calculation is performed by multiplying the monitored 

concentrations of FRM-derived total PM2.5 mass on the 10 percent 

highest days from each quarter, by the monitored fractional 

composition of PM2.5 species on the 10 percent highest PM2.5 days 

for each quarter, averaged over 3 years43 (e.g., 20 percent 

sulfate fraction multiplied by 40 μg/m3 PM2.5 equals 8 μg/m3

sulfate). 

 

42 High ambient data and model days were defined as the top 10

percent days in each quarter based on 24-hour concentrations of 

PM2.5. 

43 For this analysis, species fractions were calculated using an 

average of FRM and speciation data for the 2004-2006 time 

period. This was deemed to be representative of the 2005 

modeling year. 
175

Step 3: For each quarter, we calculate the ratio of future 

year (i.e., 2012) to base year (i.e., 2005) predictions for each 

component species44 for the top 10 percent of days based on 

predicted concentrations of 24-hour PM2.5. The result is a set 

of species-specific relative response factors (RRF) for the high 

PM2.5 days in each quarter (e.g., assume that 2005 predicted 

sulfate on the 10 percent highest PM2.5 days for a quarter for a 

particular location is 20 μg/m3 and the 2012 base case 

concentration is 16 μg/m3, then RRF for sulfate is 0.8). The 

RRFs are calculated based on the modeled concentrations at the 

single grid cell where the monitor is located.

Step 4: For each quarter, we multiply the quarterly 

species concentration (step 2) by the quarterly45 speciesspecific RRF obtained in step 3. This leads to an estimated 

future quarterly concentration for each component. (e.g., 21.0 

μg/m3 nitrate x 0.75 = future nitrate of 15.75 μg/m3).

Step 5: We sum the species concentrations to obtain 

quarterly PM2.5 values. This step is repeated for each quarter 

 

44 We did not explicitly model salt and therefore the salt 

concentration was held constant from the base to future. Also, 

blank mass was assumed to be a constant mass of 0.5 ug/m3 in 

both the base and future years. 

45 Since there is 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. 
176

and for each of the 5 years of ambient data. The highest daily 

value (from the 4 quarterly values) for each year at each 

monitor is considered to be the estimated future year 98th 

percentile 24-hour design value for that year.

Step 6: The estimated 98th percentile values for each of 

the 5 years are averaged over 3 year 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 7: 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 PM2.5

maintenance receptors..

The preceding procedures for determining future year 24-

hour PM2.5 concentrations were applied for each FRM site. The 

24-hour PM2.5 design values are truncated after the first decimal 

place. This approach is consistent with the truncation and 

rounding procedures for the 24-hour PM2.5 NAAQS. Any value that 

is greater than or equal to 35.5 μg/m3 is rounded to 36 μg/m3 and 

is violating the NAAQS. Sites with future year 5 year weighted 

average design values of 35.5 μg/m3 or greater, based on the 

projection of 5-year weighted average concentrations, are 

predicted to be nonattainment. Sites with future year maximum 
177

design values of 35.5 μg/m3 or greater are predicted to be 

maintenance sites. Note that nonattainment sites for the 24-

hour NAAQS are also maintenance sites because the maximum design 

value is always greater than or equal to the 5-year weighted 

average. For ease of reference we use the term “nonattainment 

sites” to refer to those sites that are projected to exceed the 

NAAQS based on both the average and maximum design values. 

Those sites that are projected to be attainment based on the 

average design value but exceed the NAAQS based on the maximum 

design value are referred to as maintenance sites. The 

monitoring sites that we project to be nonattainment and/or 

maintenance for the 24-hour PM2.5 NAAQS in the 2012 base case are 

the nonattainment/maintenance receptors used for assessing the 

contribution of emissions in upwind states to downwind 

nonattainment and maintenance of 24-hour PM2.5 NAAQS as part of 

this proposal.

Table IV.C-9 contains the 2003-2007 base period average and 

maximum 24-hour PM2.5 design values and the 2012 base case 

average and maximum design values for sites projected to be 2012 

nonattainment of the 24-hour PM2.5 NAAQS in 2012. Table IV.C-10 

contains this same information for projected 2012 24-hour 

maintenance sites.
178

Table IV.C-9. Average and maximum 2003-2007 and 2012 Base Case 

24-Hour PM2.5 Design Values (μg/m3) at Projected Nonattainment 

Sites.

Monitor ID State County Average 

Design 

Value 

2003-

2007

Maximum 

Design 

Value 

2003-

2007

Average 

Design 

Value 

2012

Maximum 

Design 

Value 

2012

10730023 Alabama Jefferson 44.0 44.2 40.0 40.7

10732003 Alabama Jefferson 40.3 40.8 38.1 38.9

90091123 Connecti

cut

New Haven 38.3 40.3 35.7 36.6

170310052 Illinois Cook 40.2 41.4 38.5 39.7

170310057 Illinois Cook 37.3 38.6 35.7 37.0

170310076 Illinois Cook 38.0 39.1 36.3 37.3

170311016 Illinois Cook 43.0 46.3 41.0 44.1

170312001 Illinois Cook 37.7 40.6 35.6 38.2

170313103 Illinois Cook 39.6 40.3 38.1 38.7

170313301 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
179

Monitor ID State County Average 

Design 

Value 

2003-

2007

Maximum 

Design 

Value 

2003-

2007

Average 

Design 

Value 

2012

Maximum 

Design 

Value 

2012

261470005 Michigan St. Clair 39.6 40.6 38.4 39.4

261610008 Michigan Washtenaw 39.4 40.8 38.1 39.8

261630015 Michigan Wayne 40.1 40.6 38.5 39.1

261630016 Michigan Wayne 42.9 45.4 40.6 43.0

261630019 Michigan Wayne 40.9 41.4 38.6 39.1

261630033 Michigan Wayne 43.8 44.2 42.1 42.6

261630036 Michigan Wayne 37.1 37.9 36.3 36.9

290990012 Missouri Jefferson 33.4 34.2 35.7 36.5

291831002 Missouri Saint 

Charles

33.1 34.7 35.5 37.1

295100007 Missouri St. Louis 

City

33.1 33.5 36.0 36.3

295100087 Missouri St. Louis 

City

34.3 34.7 36.4 36.9

340171003 New 

Jersey

Hudson 39.0 40.5 35.7 36.1

340172002 New 

Jersey

Hudson 41.4 41.4 38.2 38.2

340390004 New 

Jersey

Union 40.4 41.4 36.7 37.2

360050080 New York Bronx 38.8 40.2 35.9 36.2

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

391530017 Ohio Summit 38.0 39.6 35.6 37.2

420030008 Pennsylv

ania

Allegheny 39.4 39.9 35.9 36.3
180

Monitor ID State County Average 

Design 

Value 

2003-

2007

Maximum 

Design 

Value 

2003-

2007

Average 

Design 

Value 

2012

Maximum 

Design 

Value 

2012

420030064 Pennsylv

ania

Allegheny 64.2 68.2 58.8 62.3

420030093 Pennsylv

ania

Allegheny 45.6 51.5 41.1 46.2

420030116 Pennsylv

ania

Allegheny 42.5 42.5 37.1 37.1

420031008 Pennsylv

ania

Allegheny 41.3 42.8 38.0 39.3

420031301 Pennsylv

ania

Allegheny 40.3 42.4 36.6 38.6

420070014 Pennsylv

ania

Beaver 43.4 44.6 37.7 39.1

420110011 Pennsylv

ania

Berks 37.7 39.1 35.8 37.0

420210011 Pennsylv

ania

Cambria 39.0 39.4 40.3 40.7

420430401 Pennsylv

ania

Dauphin 38.0 39.0 35.7 37.1

420710007 Pennsylv

ania

Lancaster 40.8 44.0 37.7 40.1

421330008 Pennsylv

ania

York 38.2 40.7 35.9 38.8

471251009 Tennesse

e

Montgomery 36.3 37.5 36.6 37.9

540090011 West 

Virginia

Brooke 43.9 44.9 39.9 40.8

550790010 Wisconsi

n

Milwaukee 38.6 40.0 37.7 39.0

550790026 Wisconsi

n

Milwaukee 37.3 41.3 36.3 40.1

550790043 Wisconsi

n

Milwaukee 39.9 40.8 38.8 39.7

550790099 Wisconsi

n

Milwaukee 37.7 38.7 36.8 37.7

Table IV.C-10. Average and Maximum 2003-2007 and 2012 Base Case 

24-Hour PM2.5 Design Values (μg/m3) at Projected Maintenance-Only 

Sites.

Monitor ID State County

Average 

Design 

Value 

2003-

2007

Maximum 

Design 

Value 

2003-

2007

Averag

e 

Design 

Value 

2012

Maximu

m 

Design 

Value 

2012

110010041

Washington 

D.C.

Washington 

D.C. 36.3 37.8 34.0 35.6
181

Monitor ID State County

Average 

Design 

Value 

2003-

2007

Maximum 

Design 

Value 

2003-

2007

Averag

e 

Design 

Value 

2012

Maximu

m 

Design 

Value 

2012

110010042

Washington 

D.C.

Washington 

D.C. 34.9 37.0 33.0 35.6

170310022 Illinois Cook 36.6 38.6 34.9 36.6

170310050 Illinois Cook 36.1 38.0 34.1 35.8

170314007 Illinois Cook 34.3 36.4 33.6 35.7

171630010 Illinois

Saint 

Clair 33.7 34.1 35.3 35.9

171971002 Illinois Will 36.4 37.1 35.1 35.8

180390003 Indiana Elkhart 34.4 36.3 33.8 35.6

180431004 Indiana Floyd 33.2 34.5 34.3 35.7

181670023 Indiana Vigo 34.8 36.1 35.1 36.5

191390015 Iowa Muscatine 36.0 37.7 34.5 36.0

210290006 Kentucky Bullitt 34.6 35.8 35.0 36.3

211451004 Kentucky McCracken 33.6 35.9 34.4 36.8

212270007 Kentucky Warren 33.1 35.1 33.7 36.3

240031003 Maryland

Anne 

Arundel 35.5 37.4 33.8 36.7

245100035 Maryland

Baltimore 

(City) 37.7 39.2 34.7 35.5

261630001 Michigan Wayne 37.8 40.1 35.4 37.8

295100085 Missouri

St. Louis 

City 33.2 33.8 35.3 35.7

360610062 New York New York 38.8 41.6 35.3 37.0

360610079 New York New York 37.9 40.2 34.2 36.4

390350027 Ohio Cuyahoga 36.6 38.8 34.5 36.6

390350034 Ohio Cuyahoga 36.5 37.9 33.7 35.7

390810017 Ohio Jefferson 40.7 42.4 35.3 36.8

390950024 Ohio Lucas 36.3 38.6 34.2 36.5

390950026 Ohio Lucas 34.9 36.7 33.6 35.6

390990014 Ohio Mahoning 36.8 38.2 34.2 35.8

391130031 Ohio Montgomery 35.7 37.1 34.3 35.6

391351001 Ohio Preble 32.8 33.9 34.3 35.5

391550007 Ohio Trumbull 36.2 37.8 33.9 35.6

420030095

Pennsylvan

ia Allegheny 38.7 40.7 34.3 36.6

420033007

Pennsylvan

ia Allegheny 37.5 43.1 33.8 38.5

420410101

Pennsylvan

ia Cumberland 38.0 40.2 35.3 37.0

421255001

Pennsylvan

ia Washington 38.1 39.9 33.9 35.5

471650007 Tennessee Sumner 33.6 34.5 35.1 36.0

540090005

West 

Virginia Brooke 39.4 41.5 33.9 36.1

550250047 Wisconsin Dane 35.5 36.9 35.1 36.1

550790059 Wisconsin Milwaukee 35.5 37.0 34.8 36.3
182

Monitor ID State County

Average 

Design 

Value 

2003-

2007

Maximum 

Design 

Value 

2003-

2007

Averag

e 

Design 

Value 

2012

Maximu

m 

Design 

Value 

2012

551330027 Wisconsin Waukesha 35.4 36.2 34.9 35.6

(3) Methodology for 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 
183

predictions greater than or equal to 85 ppb46 using the 

predictions in the nine grid cells that include or surround the 

location of the monitoring site. The RRF for a site is the 

ratio of the mean prediction in the future year to the mean 

prediction in the 2005 base year. The RRFs were calculated on a 

site-by-site basis. 

Step 2: The RRF for each site is then multiplied by the 

2003-2007 5-year weighted average ambient design value for that 

site, yielding an 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. 

 

46 As specified in the attainment demonstration modeling 

guidance, if there are less than 10 modeled days > 85 ppb, then 

the threshold is lowered in 1 ppb increments (to as low as 70 

ppb) until there 10 days. If there are less than 5 days > 70 

ppb, then an RRF calculation is not completed for that site. 
184

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 PM2.5 NAAQS, nonattainment 

sites for the ozone NAAQS are also maintenance sites because the 

maximum design value is always greater than or equal to the 5-

year weighted 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 
185

nonattainment of the 8-hour ozone NAAQS in 2012. Table IV.C-12 

contains this same information for projected 2012 8-hour ozone 

maintenance sites.

Table IV.C-11. Average and Maximum 2003-2007 and 2012 Base Case 

8-Hour Ozone Design Values (ppb) at Projected Nonattainment 

Sites.

Monitor ID State County Average 

Design 

Value 

2003-2007

Maximum 

Design 

Value 

2003-

2007

Average 

Design 

Value 

2012

Maximum 

Design 

Value 

2012

220330003 Louisiana East Baton 

Rouge

92 96 87.8 91.6

361030002 New York Suffolk 90 91 86.3 87.2

361030009 New York Suffolk 90.3 91 85.1 85.8

421010024 Pennsylvania Philadelphia 90.3 91 85.3 86

480391004 Texas Brazoria 94.7 97 88.8 91

482010051 Texas Harris 93 98 88.4 93.1

482010055 Texas Harris 100.7 103 95.7 97.9

482010062 Texas Harris 95.7 99 90.5 93.7

482010066 Texas Harris 92.3 96 89.9 93.5

482011039 Texas Harris 96.3 100 90.5 93.9

484391002 Texas Tarrant 93.3 95 85.1 86.7

Table IV.C-12. Average and Maximum 2003-2007 and 2012 Base Case 

8-Hour Ozone Design Values (ppb) at Projected Maintenance-Only 

Sites.

Monitor ID State County Average 

Design 

Value 

2003-2007

Maximum 

Design 

Value 

2003-

2007

Average 

Design 

Value 

2012

Maximum 

Design 

Value 

2012

90010017 Connecticut Fairfield 88 90 83.1 85

90011123 Connecticut Fairfield 92.3 94 84.8 86.4

90013007 Connecticut Fairfield 90 92 84.5 86.4

90093002 Connecticut New Haven 90.3 93 82.9 85.4

130890002 Georgia DeKalb 88.7 93 81.6 85.6

131210055 Georgia Fulton 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
186

Monitor ID State County Average 

Design 

Value 

2003-2007

Maximum 

Design 

Value 

2003-

2007

Average 

Design 

Value 

2012

Maximum 

Design 

Value 

2012

482010024 Texas Harris 88 92 83.3 87.1

482010029 Texas Harris 91.7 93 84.4 85.6

482011015 Texas Harris 89 96 83.7 90.3

482011035 Texas Harris 86.3 95 82 90.3

482011050 Texas Harris 89.3 92 83.9 86.5

484392003 Texas Tarrant 93.7 95 84 85.2

3. How did EPA 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 PM2.5, 24-hour PM2.5, 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 PM2.5 and 8-hour ozone. Details of the modeling techniques 

and post-processing procedures are described in this section.

CAMx employs enhanced source apportionment 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 PM2.5 for 
187

individual receptor locations. The strength of the 

photochemical model source apportionment technique is that all 

modeled ozone and/or PM2.5 mass at a given receptor location in 

the modeling domain is tracked back to specific sources of 

emissions and boundary conditions to fully characterize culpable 

sources. This type of emissions apportionment is useful to 

understand the types of sources or regions that are contributing 

to ozone and PM2.5 estimated by the model.

Source apportionment is an alternative approach to zero-out 

modeling47 and other methods to track pollutant formation in 

photochemical models. Source apportionment completely 

characterizes source contributions to model estimated ozone and 

PM2.5, which is not possible with an emissions sensitivity 

approach such as zero-out, since the change in emissions leads 

to changes in pollutant concentrations, meaning the sum of 

estimated ozone or PM2.5 in all zero-out simulations may not 

exactly match the ozone or PM2.5 estimated in the base model 

simulation. Photochemical model source apportionment has the 

additional advantage over emissions sensitivity based approaches 

by being more computationally efficient. There is currently no 

 

47 Zero-out modeling is a technique in which all emissions are 

removed (e.g., NOx 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. 
188

technical evidence showing that one technique is clearly 

superior to the other for evaluating contributions to ozone and 

PM2.5 from various emission sources. However, since source 

apportionment explicitly tracks the formation and transport of 

all ozone and PM2.5 mass, it is particularly well suited for 

quantifying interstate contributions as part of this proposal. 

More details on the 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 PM2.5, and both zero-out and source apportionment modeling 

for ozone. The CAIR modeling was conducted at 36 km resolution 

for PM2.5 and 12 km resolution for ozone. In contrast, the 

current analysis was performed at 12 km resolution for both 

ozone and PM2.5. When choosing the modeling techniques to use 

for the Transport Rule, we carefully 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 PM2.5 and ozone with 

photochemical source apportionment. 

The EPA performed source apportionment modeling for both 

ozone and PM2.5 for the 2012 base case emissions. In this 
189

modeling we tracked the ozone and PM2.5 formed from emissions 

from sources in each upwind state in the 12 km modeling domain. 

The results were used to calculate the contributions of these 

upwind emissions to downwind nonattainment and maintenance 

receptors. The states EPA analyzed using source apportionment 

for ozone and for PM2.5 are: Alabama, Arkansas, Connecticut, 

Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Louisiana, Maine, Maryland, Massachusetts, 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 

D.C., and Wisconsin. There were also several other states that 

are only partially contained within the 12 km modeling domain 

(i.e., Colorado, Montana, New Mexico, and Wyoming). However, 

EPA did not individually track the emissions or assess the 

contribution from emissions in these states.

In contrast to CAIR, all contributions to downwind 

nonattainment and maintenance receptors for this proposal were 

calculated using a relative approach. This is similar to the 

approach used to calculate future year design 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, 
190

there are advantages of examining the relative contributions for 

both ozone and PM2.5. The main advantage of relative 

contributions is that they help to minimize biases introduced by 

model over-predictions and under-predictions. Also, the 

relative approach constrains the total contributions to the 

measurements of ozone and PM2.5 species concentrations at each 

downwind receptor. Since model performance is variable across 

the domain, EPA judged the relative approach to be the most 

appropriate technique for the Transport Rule.

a. Annual and 24-Hour PM2.5 Contribution Modeling Approach

EPA used the CAMx Particulate Source Apportionment 

Technique (PSAT) to calculate downwind PM2.5 contributions to 

nonattainment and maintenance. The CAMx PSAT is capable of 

“tagging” (i.e., tracking) source category emissions for certain

PM species and precursor emissions. For this proposal, we ran 

PSAT to tag emissions of NOX, SO2, and primary PM2.5 from the 

individual states listed previously. Due to small modeled 

concentrations of secondary organic aerosols (SOA), and the 

relatively large runtime penalty of the SOA PSAT mechanism, we 

chose not to track SOA. Through emissions pre-processing 

procedures, EPA tagged all of the anthropogenic NOX, SO2, and 

primary PM2.5 emissions in each upwind state. Each state was a 

separate tag, and the tagged emissions followed state boundaries 

(not grid cells). 
191

In the PSAT simulation NOx emissions are tracked to 

particulate nitrate concentrations, SO2 emissions are tracked to 

particulate sulfate concentrations, and primary particulates 

(organic carbon, elemental carbon, and other PM2.5) are tracked 

as primary particulates. As described earlier in section IV.B., 

the nitrate and sulfate contributions were combined and used to 

evaluate interstate contributions of PM2.5, as described in 

section IV.C.4, later.

We developed and applied several post-processing steps to 

transform the PSAT modeling outputs to PM2.5 downwind 

contributions. The approach involved processing the PSAT model 

outputs using MATS along with other post-processing software to 

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 

CAMx-predicted absolute 2012 base case concentration of the same 

species. The PSAT-derived ratios were then multiplied by the 

corresponding species component concentrations comprising the 

2012 base case PM2.5 design value. For calculating annual 

contributions, we 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-
192

hour calculations, only the upwind contribution to the highest 

quarter at each receptor was used (i.e., highest quarter based 

on 2012 PM2.5 mass). For both annual and 24-hour PM2.5, the total 

PM2.5 mass contribution was calculated by summing the 

contributions of sulfate, nitrate, ammonium, and particle bound 

water48. Details on the procedures for calculating the 

contribution metrics are provided in the AQMTSD.

b. 8-Hour Ozone Contribution Modeling Approach

EPA used the CAMx Ozone Source Apportionment Technique 

(OSAT) in order to calculate downwind 8-hour ozone contributions 

to nonattainment and maintenance. OSAT tracks the formation of 

ozone from NOX and VOC emissions. Through emissions preprocessing procedures, EPA tagged all of the NOX 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 NOX and VOC were tracked in the 

OSAT simulation. Upwind NOX and VOC emissions were tracked to 

 

48 The water and ammonium contributions are calculated by MATS 

using the default assumptions that were used to calculate future 

year 2012 PM2.5 concentrations. The ammonium contribution is 

calculated assuming that all particulate nitrate is in the form 

of ammonium nitrate and the ammonium associated with sulfate is 

based on the degree of 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. 
193

downwind ozone concentrations. There are several postprocessing steps needed to transform the raw model outputs to 

ozone downwind contributions. We developed and applied several 

post-processing steps to transform the OSAT modeling outputs to 

ozone contributions at downwind receptors. The approach for 

ozone was similar to the approach for PM2.5 in that the OSAT 

model outputs were processed using MATS along with other postprocessing software to calculate the contribution of each upwind 

state to each downwind nonattainment and/or maintenance 

receptor. This process involved calculating a ratio which uses 

the OSAT-predicted absolute contribution of ozone coupled with 

the CAMx-predicted absolute 2012 base case ozone concentration. 

The OSAT-derived ratios were then multiplied by the 

corresponding 2012 base case ozone design value. The 

contributions to each downwind receptor are averaged across all 

days with modeled 2012 base case concentrations greater than 85 

ppb49 (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

 

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. 
194

The previous steps provide the details for calculating 8-

hour ozone and annual and 24-hour PM2.5 contributions to all 

downwind receptors. After the post-processing of the model 

results is complete, we then evaluate the contributions of each 

upwind state to nonattainment and maintenance receptors. The 

nonattainment receptors are those monitoring sites, which are 

projected to exceed the NAAQS in the 2012 base case, based on 5-

year weighted average design values. The maintenance receptors 

are those monitoring sites which are projected to exceed the 

NAAQS in the 2012 base case based on the highest design value 

period. The upwind ozone and PM2.5 contributions from each state 

are calculated for each downwind receptor. Contributions to 

nonattainment and maintenance receptors are evaluated 

independently for each state to determine if they are above the 

1 percent threshold criteria. 

For each upwind state, the maximum contribution to 

nonattainment is calculated based on the single largest 

contribution to a future year (2012) downwind nonattainment 

receptor. The maximum contribution to maintenance is calculated 

based on the single largest 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 
195

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 

PM2.5, 24-Hour PM2.5, and 8-Hour ozone nonattainment and 

maintenance?

a. Contributions to Annual and 24-Hour PM2.5 Nonattainment and 

Maintenance

In this section, we present the interstate contributions 

from emissions in upwind states to downwind nonattainment and 

maintenance sites for the annual PM2.5 NAAQS. We also present 

the interstate contributions from emissions in upwind states to 

downwind nonattainment and maintenance sites for the 24-hour 

PM2.5 NAAQS. As described previously in section IV.B., states 

which contribute 0.15 μg/m3 or more to annual PM2.5 nonattainment 

or maintenance in another state are identified as states with 

contributions to downwind attainment and maintenance sites large 

enough to warrant further analysis. For 24-hour PM2.5, states 

which contribute 0.35 μg/m3 or more to 24-hour PM2.5 nonattainment 

or maintenance in another state are identified as states with 

contributions to downwind attainment and maintenance sites large 

enough to warrant further analysis. As described previously in 

section IV.C.3, we performed air quality modeling to quantify 

the contributions to annual and 24-hour PM2.5 from emissions in 
196

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 PM2.5, we calculated each state’s contribution to 

each of the 32 monitoring sites that are projected to be 

nonattainment and each of the 16 sites that are projected to 

have maintenance problems for the annual PM2.5 NAAQS in the 2012 

base case. The maximum contribution from each state to annual 

PM2.5 nonattainment in downwind sites is provided in Table IV.C13. The maximum contribution from each state to annual PM2.5

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 PM2.5 NAAQS 

are provided in the AQMTSD.
197

Table IV.C-13. Maximum contribution to downwind annual PM2.5

(μg/m3) nonattainment and maintenance for each of 37 States.

 

Upwind State

Maximum 

Downwind 

Contribution to 

Nonattainment 

for 

Annual PM2.5

(ug/m3)

Maximum 

Downwind 

Contribution 

to Maintenance 

for

Annual PM2.5 

(ug/m3)

Alabama 0.46 0.18

Arkansas 0.09 0.04

Connecticut 0.04 0.09

Delaware 0.20 0.14

Florida 0.29 0.07

Georgia 0.63 0.18

Illinois 1.01 0.63

Indiana 2.09 1.78

Iowa 0.31 0.30

Kansas 0.09 0.05

Kentucky 1.68 1.01

Louisiana 0.11 0.34

Maine 0.01 0.02

Maryland 0.62 0.55

Massachusetts 0.07 0.13

Michigan 0.72 0.71

Minnesota 0.19 0.17

Mississippi 0.07 0.03

Missouri 1.38 0.27

Nebraska 0.08 0.06

New Hampshire 0.01 0.02

New Jersey 0.34 0.68

New York 0.49 0.47

North 

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
198

Upwind State

Maximum 

Downwind 

Contribution to 

Nonattainment 

for 

Annual PM2.5

(ug/m3)

Maximum 

Downwind 

Contribution 

to Maintenance 

for

Annual PM2.5 

(ug/m3)

Tennessee 0.68 0.64

Texas 0.13 0.06

Vermont 0.00 0.00

Virginia 0.36 0.37

West Virginia 0.98 1.17

Wisconsin 0.46 0.42

Based on the state-by-state contribution analysis, there 

are 22 states and the District of Columbia50 which contribute 

0.15 μg/m3 or more to downwind annual PM2.5 nonattainment. These 

states are: Alabama, the District of Columbia, Delaware, 

Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Maryland, 

Michigan, Minnesota, Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 

Virginia, West Virginia, and Wisconsin. In Table IV.C-14, we 

provide a list of the downwind nonattainment sites to which each 

upwind State contributes 0.15 μg/m3 or more (i.e., the upwind 

State-to-downwind nonattainment “linkages”). 

 

50 EPA combined Maryland and the District of Columbia as a 

single entity in our contribution 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.
199

There are 19 states and the District of Columbia51 which 

contribute 0.15 μg/m3 or more to downwind annual PM2.5

maintenance. These states are: Alabama, the District of 

Columbia, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, Missouri, New Jersey, New York, 

Ohio, 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 

μg/m3 or more (i.e., the upwind State-to-downwind maintenance 

“linkages”). 

 

51 As noted above, we combined Maryland and the District of 

Columbia as a single entity in our 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.
200

Table IV.C-14. Upwind State-to-Downwind Nonattainment Site “Linkages” for Annual PM2.5.

Upwind

State

Number 

of

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

Alabama 6

Bibb, GA 

(130210007)

Clayton, GA 

(130630091)

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 

Jefferson, 

KY 

Wayne, MI 

(261630015)

Wayne, MI 

(261630033)

Butler, OH 

(390170016)

Cuyahoga, 

OH 

Cuyahoga, 

OH 
201

Upwind

State

Number 

of

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

(171630010) (211110043) (390350038) (390350045)

Cuyahoga, 

OH 

(390350060)

Hamilton, 

OH 

(390618001)

Hamilton, 

OH 

(390610014)

Hamilton, 

OH 

(390610042)

Hamilton, 

OH 

(390610043)

Hamilton, 

OH 

(390617001)

Allegheny, 

PA 

(420030064)

Allegheny, 

PA 

(420031301)

Beaver, PA 

(420070014)

Lancaster, 

PA 

(420710007)

York, PA 

(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 

Butler, OH 

(390170016)

Cuyahoga, 

OH 

Cuyahoga, 

OH 

Cuyahoga, 

OH 

Hamilton, 

OH 
202

Upwind

State

Number 

of

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

(211110043) (390350038) (390350045) (390350060) (390610014)

Hamilton, 

OH 

(390610042)

Hamilton, 

OH 

(390610043)

Hamilton, 

OH 

(390617001)

Hamilton, 

OH 

(390618001)

Allegheny, 

PA 

(420030064)

Allegheny, 

PA 

(420031301)

Beaver, PA 

(420070014)

Lancaster, 

PA 

(420710007)

York, PA 

(421330008)

Cabell, WV 

(540110006)

Kanawha, WV 

(540391005)

Minnesota 1

Cook, IL 

(170310052)

Missouri 17

Cook, IL 

(170310052)

Madison, IL 

(171191007)

Saint 

Clair, IL 

(171630010)

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)

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)
203

Upwind

State

Number 

of

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

Saint 

Clair, IL 

(171630010)

Clark, IN 

(180190006)

Dubois, IN 

(180372001)

Marion, IN 

(180970078)

Marion, IN

(180970081)

Marion, IN 

(180970083)

Jefferson, 

KY 

(211110043)

Wayne, MI 

(261630015)

Wayne, MI 

(261630033)

Allegheny, 

PA 

(420030064)

Allegheny, 

PA 

(420031301)

Beaver, PA 

(420070014)

Lancaster, 

PA 

(420710007)

York, PA 

(421330008)

Cabell, WV 

(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 

Hamilton, 

OH 

Hamilton, 

OH 

Allegheny, 

PA 

Allegheny, 

PA 

Beaver, PA 

(420070014)

Cabell, WV 

(540110006)
204

Upwind

State

Number 

of

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

(390610043) (390617001) (390618001) (420030064) (420031301)

Kanawha, WV 

(540391005)

Virginia 4

Lancaster, 

PA

(420710007)

York, PA 

(421330008)

Cabell, WV 

(540110006)

Kanawha, WV 

(540391005)

West 

Virginia 25

Fulton, GA 

(131210039)

Bibb, GA 

(130210007)

Clayton, GA 

(130630091)

Clark, IN 

(180190006)

Marion, IN 

(180970078)

Marion, IN 

(180970081)

Marion, IN 

(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)
205

Table IV.C-15. Upwind State-to-Downwind Maintenance Site “Linkages” for Annual PM2.5.

Upwind

State

Number 

of

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

Alabama 1

Jefferson, KY 

(211110044)

Georgia 1

Jefferson, KY 

(211110044)

Illinois 13

Jefferson, KY 

(211110044)

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 

Brooke, WV 

(540090005

Hancock, WV 

(540291004)

Marion, WV 

(540490006)
206

Upwind

State

Number 

of

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

(540030003) )

Louisiana 1

Harris, TX 

(482011035)

Maryland 2

Berks, PA

(420110011)

Berkeley, 

WV 

(540030003)

Michigan 15

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Jefferson, 

KY 

(211110044

)

New York, NY 

(360610056)

Cuyahoga, 

OH 

(390350027)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390610040)

Jefferson, OH 

(390811001)

Montgomery, 

OH 

(391130032)

Stark, OH 

(391510017

)

Berks, PA

(420110011)

Berkeley, 

WV 

(540030003)

Brooke, WV 

(540090005)

Hancock, WV 

(540291004)

Marion, WV 

(540490006)

Minnesota 1

Cook, IL 

(170316005)

Missouri 6

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Jefferson, 

KY 

(211110044

)

Hamilton, OH 

(390610040)

Montgomery, 

OH 

(391130032)

Stark, OH 

(391510017)

New 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 

New York, NY 

(360610056)

Berks, PA

(420110011)

Berkeley, WV 

(540030003)

Brooke, WV 

(540090005)
207

Upwind

State

Number 

of

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

(211110044

)

Hancock, WV 

(540291004)

Marion, WV 

(540490006)

Pennsylvan

ia 14

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Jefferson, 

KY 

(211110044

)

New York, NY 

(360610056)

Cuyahoga, 

OH 

(390350027)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390610040)

Jefferson, OH 

(390811001)

Montgomery, 

OH 

(391130032)

Stark, OH 

(391510017

)

Berkeley, WV 

(540030003)

Brooke, WV 

(540090005)

Hancock, WV 

(540291004)

Marion, WV 

(540490006)

Tennessee 10

Jefferson, KY 

(211110044)

Cuyahoga, 

OH 

(390350027)

Cuyahoga, 

OH 

(390350065

)

Hamilton, OH 

(390610040)

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)

Wisconsin 2

Cook, IL 

(170313301)

Cook, IL 

(170316005)
208

For 24-hour PM2.5, we calculated each state’s 

contribution to each of the 92 monitoring sites that are 

projected to be nonattainment and each of the 38 sites that 

are projected to have maintenance problems for the 24-hour 

PM2.5 NAAQS in the 2012 base case. The maximum contribution 

from each state to 24-hour PM2.5 nonattainment in downwind 

sites is provided in Table IV.C-16. The maximum 

contribution from each state to 24-hour PM2.5 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 PM2.5

NAAQS are provided in the AQMTSD. 

Table IV.C-16. Maximum Contribution to Downwind 24-Hour 

PM2.5 (μg/m3) Nonattainment and Maintenance for each of 37 

States.

Upwind State

Maximum Downwind

Contribution to 

Nonattainment

for 24-Hour PM2.5

(ug/m3)

Maximum Downwind 

Contribution to 

Maintenance

for 24-Hour PM2.5

(ug/m3)

Alabama 0.48 0.32

Arkansas 0.20 0.17

Connecticut 0.41 0.70

Delaware 0.50 0.36

Florida 0.08 0.08

Georgia 0.95 0.41

Illinois 7.28 6.57

Indiana 9.91 8.94

Iowa 1.87 1.67

Kansas 0.77 0.45

Kentucky 6.53 6.91

Louisiana 0.23 0.18

Maine 0.19 0.19
209

Upwind State

Maximum Downwind

Contribution to 

Nonattainment

for 24-Hour PM2.5

(ug/m3)

Maximum Downwind 

Contribution to 

Maintenance

for 24-Hour PM2.5

(ug/m3)

Maryland 2.52 2.84

Massachusetts 0.67 0.71

Michigan 2.35 3.35

Minnesota 0.91 0.86

Mississippi 0.09 0.04

Missouri 5.03 4.82

Nebraska 0.62 0.39

New Hampshire 0.21 0.23

New Jersey 2.69 4.74

New York 5.82 1.17

North 

Carolina 0.50 0.45

North Dakota 0.27 0.15

Ohio 5.84 5.56

Oklahoma 0.16 0.21

Pennsylvania 3.67 4.86

Rhode Island 0.05 0.06

South 

Carolina 0.19 0.19

South Dakota 0.13 0.09

Tennessee 3.92 4.70

Texas 0.21 0.28

Vermont 0.06 0.07

Virginia 1.32 2.26

West Virginia 3.51 4.83

Wisconsin 0.80 1.01

Based on the state-by-state contribution analysis, 

there are 24 States and the District of Columbia52 which 

contribute 0.35 μg/m3 or more to downwind 24-hour PM2.5

 

52

 As noted above, we combined Maryland and the District of 

Columbia as a single entity in our 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.
210

nonattainment. These states are: Alabama, the District of 

Columbia, Connecticut, Delaware, Georgia, Illinois, 

Indiana, Iowa, Kansas, Kentucky, Maryland, Massachusetts, 

Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 

York, North Carolina, Ohio, Pennsylvania, Tennessee, 

Virginia, West Virginia, and Wisconsin. In Table IV.C-17, 

we provide a list of the downwind nonattainment counties to 

which each upwind State contributes 0.35 μg/m3 or more 

(i.e., the upwind State-to-downwind nonattainment 

“linkages”). 

There are 23 states and the District of Columbia which 

contribute 0.35 μg/m3 or more to downwind 24-hour PM2.5

maintenance. These states are: Connecticut, Delaware, the 

District of Columbia, Georgia, Illinois, Indiana, Iowa, 

Kansas, Kentucky, Maryland, Massachusetts, Michigan, 

Minnesota, Missouri, Nebraska, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West 

Virginia, and Wisconsin. In Table IV.C-18, we provide a 

list of the downwind maintenance sites to which each upwind 

State contributes 0.35 μg/m3 or more (i.e., the upwind 

State-to-downwind maintenance “linkages”). 
211

Table IV.C-17. Upwind State-to-Downwind Nonattainment Site “Linkages” for 24-Hour PM2.5.

Upwind

State

Number of

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

Alabama 5

Monroe, MI 

(261150005)

Wayne, MI 

(261630015)

Hamilton, OH 

(390610006)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390618001)

Connecticut 3

Hudson, NJ 

(340172002)

New York, NY 

(360610056)

New York, NY 

(360610128)

Delaware 2

Union, NJ 

(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)
212

Upwind

State

Number of

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

Cuyahoga, OH 

(390350060)

Cuyahoga, OH 

(390350065)

Franklin, OH 

(390490024)

Franklin, OH 

(390490025)

Hamilton, OH 

(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)
213

Upwind

State

Number of

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

Hamilton, OH 

(390618001)

Jefferson, OH 

(390811001)

Montgomery, OH 

(391130032)

Summit, OH 

(391530017)

Allegheny, PA 

(420030008)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030093)

Allegheny, PA 

(420030116)

Allegheny, PA 

(420031008)

Allegheny, PA 

(420031301)

Beaver, PA 

(420070014)

Berks, PA

(420110011)

Cambria, PA 

(420210011)

Dauphin, PA 

(420430401)

York, PA 

(421330008)

Montgomery, TN 

(471251009)

Brooke, WV 

(540090011)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Milwaukee, WI 

(550790043)

Milwaukee, WI 

(550790099)

Iowa 17

Cook, IL 

(170310052)

Cook, IL 

(170310057)

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)

St. Clair, MI 

(261470005)

Washtenaw, MI 

(261610008)

Wayne, MI 

(261630015)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Wayne, MI 

(261630036)

Jefferson, MO 

(290990012)

Saint Charles, 

MO (291831002)

St. Louis 

City, MO 

St. Louis 

City, MO 

Hudson, NJ 

(340171003)
214

Upwind

State

Number of

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

(295100007) (295100087)

Union, NJ 

(340390004)

Bronx, NY 

(360050080)

New York, NY 

(360610128)

Butler, OH 

(390170003)

Butler, OH 

(390170016)

Butler, OH 

(390170017)

Butler, OH 

(390171004)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Cuyahoga, OH 

(390350065)

Franklin, OH 

(390490024)

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 

St. Louis 

City, MO 

New York, NY 

(360610128)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)
215

Upwind

State

Number of

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

(295100007) (295100087)

Cuyahoga, OH 

(390350065)

Franklin, OH 

(390490024)

Franklin, OH 

(390490025)

Hamilton, OH 

(390610014)

Hamilton, OH 

(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)
216

Upwind

State

Number of

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

Hamilton, OH 

(390610006)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610040)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390610043)

Hamilton, OH 

(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)

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)
217

Upwind

State

Number of

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

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)
218

Upwind

State

Number of

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

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)
219

Upwind

State

Number of

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

Oakland, MI 

(261250001)

St. Clair, MI 

(261470005)

Washtenaw, MI 

(261610008)

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)

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)
220

Upwind

State

Number of

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

Tippecanoe, 

IN 

(181570008)

Scott, IA 

(191630019)

Jefferson, KY 

(211110043)

Jefferson, KY 

(211110044)

Jefferson, KY 

(211110048)

Baltimore 

City, MD 

(245100040)

Baltimore 

City, MD 

(245100049)

Monroe, MI 

(261150005)

Oakland, MI 

(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)
221

Table IV.C-18. Upwind State-to-Downwind Maintenance Site “Linkages” for 24-Hour PM2.5.

Upwind

State

Number of

Linkages Counties Containing Downwind 24-Hour PM2.5 Maintenance 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)
222

Upwind

State

Number of

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

Jefferson, OH 

(390810017)

Lucas, OH 

(390950024)

Lucas, OH 

(390950026)

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)

Dane, WI 

(550250047)

Milwaukee, WI 

(550790059)

Waukesha, WI 

(551330027)

Kansas 2

Muscatine, IA 

(191390015)

Milwaukee, WI 

(550790059)

Kentucky 33

District of 

Columbia 

(110010041)

District of 

Columbia 

(110010042)

Cook, IL 

(170310022)

Cook, IL 

(170310050)

Cook, IL 

(170314007)

Saint Clair, 

IL (171630010)

Will, IL 

(171971002)

Elkhart, IN 

(180390003)

Floyd, IN 

(180431004)

Vigo, IN 

(181670023)

Muscatine, 

IA 

(191390015)

Anne Arundel, 

MD (240031003)

Wayne, MI 

(261630001)

St. Louis 

City, MO 

(295100085)

New York, NY 

(360610062)

New York, NY 

(360610079)

Cuyahoga, OH 

(390350027)

Cuyahoga, OH 

(390350034)

Jefferson, OH 

(390810017)

Lucas, OH 

(390950024)

Lucas, OH 

(390950026)

Mahoning, OH 

(390990014)

Montgomery, 

OH 

(391130031)

Preble, OH 

(391351001)

Trumbull, OH

(391550007)

Allegheny, PA 

(420030095)

Allegheny, PA 

(420033007)

Washington, PA 

(421255001)

Sumner, TN 

(471650007)

Brooke, WV 

(540090005)

Dane, WI 

(550250047)

Milwaukee, WI 

(550790059)

Waukesha, WI 

(551330027)
223

Upwind

State

Number of

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

Maryland 5

District of 

Columbia 

(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)
224

Upwind

State

Number of

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

New Jersey 5

District of 

Columbia 

(110010041)

Anne Arundel, 

MD (240031003)

New York, NY 

(360610062)

New York, NY 

(360610079)

Cumberland, 

PA 

(420410101)

New York 9

District of 

Columbia 

(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)
225

Upwind

State

Number of

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

Cuyahoga, OH 

(390350027)

Cuyahoga, OH 

(390350034)

Jefferson, OH 

(390810017)

Lucas, OH 

(390950024)

Lucas, OH 

(390950026)

Mahoning, OH 

(390990014)

Montgomery, OH 

(391130031)

Preble, OH 

(391351001)

Trumbull, OH 

(391550007)

Sumner, TN 

(471650007)

Brooke, WV 

(540090005)

Dane, WI 

(550250047)

Milwaukee, WI 

(550790059)

Waukesha, WI 

(551330027)

Tennessee 21

Cook, IL 

(170314007)

Saint Clair, 

IL (171630010)

Will, IL 

(171971002)

Elkhart, IN 

(180390003)

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)
226

Upwind

State

Number of

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

Montgomery, OH 

(391130031)

Preble, OH 

(391351001)

Trumbull, OH 

(391550007)

Allegheny, PA 

(420030095)

Allegheny, 

PA 

(420033007)

Cumberland, PA 

(420410101)

Washington, PA 

(421255001)

Sumner, TN 

(471650007)

Dane, WI 

(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)
227

b. Results of 8-Hour Ozone Contribution Modeling

In this section, we present the interstate 

contributions from emissions in upwind states to downwind 

nonattainment and maintenance sites for the ozone NAAQS. 

As described previously in section IV.B., states which 

contribute 0.8 ppb or more to 8-hour ozone nonattainment or 

maintenance in another state are identified as states with 

contributions to downwind attainment and maintenance sites 

large enough to warrant further analysis. We performed air 

quality modeling to quantify the contributions to 8-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 
228

and each of 1453 sites that are projected to have 

maintenance problems for the 8-hour ozone NAAQS in the 2012 

Base Case. The maximum contribution from each state to 8-

hour ozone nonattainment in downwind sites is provided in 

Table IV.C-19. The maximum contribution from each state to 

8-hour ozone maintenance in downwind sites is also provided 

in Table IV.C-19. The contributions from each state to all 

projected 2012 nonattainment and maintenance sites for the 

8-hour ozone NAAQS are provided in the AQMTSD. 

Table IV.C-19. Maximum Contribution to Downwind 8-Hour 

Ozone Nonattainment and Maintenance for Each of 37 States.

Upwind State

Maximum 

Downwind 

Contribution 

to 

Nonattainment 

for Ozone 

(ppb)

Maximum 

Downwind 

Contribution 

to Maintenance 

for

Ozone (ppb)

Alabama 4.7 4.7

Arkansas 1.4 1.8

Connecticut 1.7 1.6

Delaware 3.3 2.5

Florida 0.8 2.1

Georgia 2.1 1.7

Illinois 0.8 0.6

Indiana 1.1 1.0

Iowa 0.3 0.3

Kansas 0.6 0.8

Kentucky 2.3 1.8

 

53 For two of the 16 projected maintenance sites (Harris 

Co., Texas sites 482011015 and 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.
229

Upwind State

Maximum 

Downwind 

Contribution 

to 

Nonattainment 

for Ozone 

(ppb)

Maximum 

Downwind 

Contribution 

to Maintenance 

for

Ozone (ppb)

Louisiana 11.4 10.6

Maine 0.0 0.0

Maryland 6.0 4.1

Massachusetts 0.6 0.5

Michigan 0.9 0.5

Minnesota 0.1 0.2

Mississippi 5.2 2.5

Missouri 0.7 0.6

Nebraska 0.2 0.2

New Hampshire 0.1 0.1

New Jersey 16.8 15.8

New York 0.4 22.7

North 

Carolina 1.7 2.0

North Dakota 0.1 0.0

Ohio 2.8 2.6

Oklahoma 2.1 2.7

Pennsylvania 8.9 8.1

Rhode Island 0.1 0.1

South 

Carolina 0.6 0.8

South Dakota 0.0 0.0

Tennessee 1.6 3.0

Texas 1.6 0.6

Vermont 0.0 0.1

Virginia 4.2 4.5

West Virginia 2.7 2.3

Wisconsin 0.3 0.2
230

Based on the state-by-state contribution analysis, 

there are 22 States and the District of Columbia54 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-todownwind nonattainment “linkages”).

There are 22 States and the District of Columbia which 

contribute 0.8 ppb or more to downwind 8-hour ozone 

maintenance. These states are: Alabama, Arkansas, 

Connecticut, Delaware, the District of Columbia, Florida, 

Georgia, Indiana, Kansas, Kentucky, Louisiana, Maryland, 

Mississippi, New Jersey, New York, North Carolina, Ohio, 

Oklahoma, Pennsylvania, South Carolina, Tennessee, 

 

54

 As noted above, we combined Maryland and the District of 

Columbia as a single entity in our 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.
231

Virginia, and West Virginia. In Table IV.C-21, we provide 

a list of the downwind nonattainment counties to which each 

upwind State contributes 0.8 ppb or more (i.e., the upwind 

State-to-downwind nonattainment “linkages”).
232

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

Upwind

State

Number 

of

Linkages

Counties Containing Downwind 8-Hour Ozone Nonattainment Sites (Monitoring 

Site ID)

Alabama 8

East Baton 

Rouge, LA 

(220330003)

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Harris, TX 

(482010062)

Harris, TX 

(482010066)

Harris, TX 

(482011039)

Tarrant, TX 

(484391002)

Arkansas 3

East Baton 

Rouge, LA 

(220330003)

Brazoria, TX 

(480391004)

Tarrant, TX 

(484391002)

Connecticut 1

Suffolk, NY 

(361030009)

Delaware 3

Suffolk, NY 

(361030002)

Suffolk, NY 

(361030009)

Philadelphia, 

PA 

(421010024)

Florida 2

Harris, TX 

(482010062)

Tarrant, TX 

(484391002)

Georgia 7

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Harris, TX 

(482010062)

Harris, TX 

(482010066)

Harris, TX 

(482011039)

Tarrant, TX 

(484391002)

Illinois 2

Suffolk, NY 

(361030009)

Harris, TX 

(482010055)

Indiana 3

Suffolk, NY 

(361030002)

Suffolk, NY 

(361030009)

Philadelphia, 

PA 

(421010024)

Kentucky 6

Suffolk, NY 

(361030002)

Philadelphia, 

PA 

(421010024)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Harris, TX 

(482010062)

Harris, TX 

(482011039)
233

Upwind

State

Number 

of

Linkages

Counties Containing Downwind 8-Hour Ozone Nonattainment Sites (Monitoring 

Site ID)

Louisiana 7

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Harris, TX 

(482010062)

Harris, TX 

(482010066)

Harris, TX 

(482011039)

Tarrant, TX 

(484391002)

Maryland 3

Suffolk, NY 

(361030002)

Suffolk, NY 

(361030009)

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)
234

Upwind

State

Number 

of

Linkages

Counties Containing Downwind 8-Hour Ozone Nonattainment Sites (Monitoring 

Site ID)

Harris, TX 

(482011039)

Texas 1

East Baton 

Rouge, LA 

(220330003)

Virginia 3

Suffolk, NY 

(361030002)

Suffolk, NY 

(361030009)

Philadelphia, 

PA 

(421010024)

West 

Virginia 3

Suffolk, NY 

(361030002)

Suffolk, NY 

(361030009)

Philadelphia, 

PA 

(421010024)

Table IV.C-21. Upwind State-to-Downwind Maintenance “Linkages” for 8-Hour Ozone.

Upwind

State

Number 

of

Linkages Counties Containing Downwind 8-Hour Ozone Maintenance Sites (Monitoring Site ID)

Alabama 6

DeKalb, GA 

(130890002)

Fulton, GA 

(131210055)

Harris, TX 

(482010024)

Harris, TX 

(482010029)

Harris, TX 

(482011050)

Tarrant, TX 

(484392003)

Arkansas 4

Dallas, TX 

(481130069)

Dallas, TX 

(481130087)

Harris, TX 

(482011050)

Tarrant, TX 

(484392003)

Connecticut 1

Westchester, 

NY 

(361192004)

Delaware 1

Bucks, PA 

(420170012)

Florida 4

DeKalb, GA 

(130890002)

Fulton, GA 

(131210055)

Harris, TX 

(482010024)

Harris, TX 

(482010029)
235

Georgia 4

Harris, TX 

(482010024)

Harris, TX 

(482010029)

Harris, TX 

(482011050)

Tarrant, TX 

(484392003)

Indiana 4

Fairfield, 

CT 

(90010017)

New Haven, 

CT 

(90093002)

Westchester, 

NY 

(361192004)

Bucks, PA 

(420170012)

Kansas 1

Dallas, TX 

(481130069)

Kentucky 6

Fairfield, 

CT 

(90010017)

Fairfield, 

CT 

(90011123)

Fairfield, 

CT 

(90013007)

New Haven, 

CT 

(90093002)

Westchester, 

NY 

(361192004)

Bucks, PA 

(420170012)

Louisiana 6

Dallas, TX 

(481130069)

Dallas, TX 

(481130087)

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)
236

Pennsylvania 5

Fairfield, 

CT 

(90010017)

Fairfield, 

CT 

(90011123)

Fairfield, 

CT 

(90013007)

New Haven, 

CT 

(90093002)

Westchester, 

NY 

(361192004)

South 

Carolina 2

Fulton, GA 

(131210055)

Harris, TX 

(482010029)

Tennessee 5

DeKalb, GA 

(130890002)

Fulton, GA 

(131210055)

Bucks, PA 

(420170012)

Harris, TX 

(482010024)

Harris, TX 

(482011050)

Virginia 6

Fairfield, 

CT 

(90010017)

Fairfield, 

CT 

(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)
237

D. Proposed Methodology to Quantify Emissions that 

Significantly Contribute or Interfere with Maintenance

In this section, EPA explains its general approach to 

quantifying the amount of emissions that represent significant 

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 PM2.5 NAAQS and the 2006 24-hour PM2.5 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, NOX 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 PM2.5 NAAQS, this proposal finds 

that 24 eastern states have SO2 and NOx emission reduction 

responsibilities. We apply the proposed methodology to fully 
238

quantify the SO2 and NOX 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 PM2.5 standard or that more SO2 

emissions should be included, we believe that we will be able to 

issue a supplemental proposal and finalize a rule fully 

quantifying significant contribution and interference with 

maintenance with respect to the 24-hour PM2.5 standard. If 
239

further analysis shows that other reductions should be 

considered as part of significant contribution or interference 

with maintenance with respect to the 24-hour PM2.5 standard these 

emissions would be fully addressed in a separate rulemaking

effort.

1. Explanation of Proposed Approach to Quantify Significant 

Contribution

After using air quality analysis to identify upwind states 

that are “linked” to downwind air quality monitoring sites with 

nonattainment and maintenance problems because the upwind 

states’ emissions contribute one percent or more to the air 

quality value at the downwind site, EPA quantifies the portion 

of each state’s contribution that constitutes its “significant 

contribution” and “interference with maintenance.” 

This 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 PM2.5 NAAQS and the ozone NAAQS.

For this portion of the analysis, EPA expands upon the 

methodology used in the NOX SIP Call and CAIR, but modifies it in 

significant respects. In the NOX SIP Call and CAIR, EPA’s 

methodology relied upon defining significant contribution as 

those emissions that could be removed with the use of “highly 

cost effective” controls. In this action, rather than relying 
240

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 NOX SIP Call and CAIR where EPA only defined an amount of 

reductions needed to address significant contribution to 

nonattainment, EPA is proposing to define an amount of emissions 

reductions that addresses both significant contribution to 

nonattainment and interference with maintenance.

The methodology takes into account both the D.C. Circuit 

Court’s determination that EPA may consider cost when measuring 

significant contribution, Michigan, 213 F.3d at 679, and its 

rejection of the manner in which cost was used in the CAIR 

analysis, North Carolina, 531 F.3d at 917. It also recognizes 

that the Court accepted -- but did not require -- EPA’s use of a 

single, uniform cost threshold to measure significant 

contribution. Michigan, 213 F.3d 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 NOX 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 in 
241

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 the downwind state, at different 

cost-per-ton levels, would have on air quality at downwind 

monitor sites that had nonattainment and/or maintenance 

problems. 

In step three, EPA examines cost and air quality information 

to identify cost “breakpoints.” Breakpoints are the places 

where there is a noticeable change on one of the cost curves, 

such as a point where a large reduction occurs because a certain 

type of emissions control becomes cost-effective. EPA then uses 

a multi-factor assessment to determine the amount of emissions 

that represents significant contribution to nonattainment and 

interference with maintenance. The factors considered include 

both the air quality and cost considerations used in developing 

the breakpoints along with additional air quality and cost 

considerations. This assessment is performed for each 
242

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 SO2 and NOX. The methodology also allows EPA, where 

appropriate, to define multiple cost thresholds that vary for a 

particular pollutant for different upwind states. 

In step four, EPA quantifies the emissions reductions 

available in each “linked” state at the appropriate cost 

threshold. This information is then used to develop a state 

“budget,” representing the 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 
243

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 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. 
244

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 
245

controls to demonstrate timely attainment of the NAAQS despite 

any pollution transport from upwind states that is not 

eliminated under section 110(a)(2)(D). Given this structure, 

interpreting significant contribution and interfere with 

maintenance 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, PM2.5 and ozone problems result 

from a combination of local, in-state, and upwind state 

emissions. EPA’s proposed methodology for determining what 

portion of a state’s total contribution is its significant 

contribution and interference with maintenance is intended to

assign a substantial but reasonable amount of responsibility to 

upwind states.

There are several reasons that EPA believes upwind state 

sources contributing to air quality degradation in a downwind 

state should bear substantial responsibility to control their 

emissions. First, the plain language of this good neighbor 

provision requires upwind states to prohibit emissions that 

significantly contribute to nonattainment or interfere with 

maintenance in a downwind state. Second, interstate pollution 

transport increases pollution levels and health risks in the 

downwind state. Third, the influx of pollution from upwind 

states raises the pollution level in a downwind state, making it 
246

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 states55. In 

addition, in almost all cases, states with downwind 

nonattainment and maintenance areas are also required to reduce 

emissions based on the fact that they are also upwind states 

 

55 We also recognize that there can be reasons to depart from an 

equal cost per ton allocation of responsibility before a 

receptor’s attainment and maintenance problem is fully resolved, 

such as when a receptor’s air quality problem has an unusually 

high local component.
247

that are “linked” to other downwind states with nonattainment 

and maintenance problems.

The proposed methodology also directly ties each state’s 

reduction requirements to EPA’s analysis of that state’s 

significant contribution and interference with maintenance. The 

required reductions would provide very substantial air quality 

improvements. For the annual PM2.5 standard, EPA projects that 

this rule will help assure that all but one area in the East 

attain the standard by 2014. It will also help a number of 

areas achieve the standard earlier. The methodology provides 

similar assistance for ozone, assuring upwind reductions that 

will mitigate the amount that downwind states may need to do. 

It reduces ozone 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 
248

for EGUs in a state. In other words, EPA determined for 

specific cost per ton thresholds, the emission reductions that 

would be achieved in a state if all EGUs in that state used all 

emission controls and emission reduction measures available at 

that cost threshold. The zero point of the curve shows what 

emissions would occur absent any additional investment in 

emissions reductions (i.e., the base case emissions). 

Additional points on the curves show the emissions that would 

occur after the installation of all controls that could be 

installed at specific cost levels (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 SO2 and 

annual NOX can be found in section IV.D.2.a of this preamble and 

the curves for ozone season NOX in section IV.D.2.b. For more 

detail on the development of the cost curves, see the TSD, 
249

“Analysis to Quantify Significant Contribution,” in the docket 

for this rule. 

Although the cost curves presented in this proposal only 

include EGU reductions, EPA also conducted a preliminary 

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 thresholds based on that analysis. EPA then 

re-examined 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 emission reductions is discussed in more detail in 

section IV.D.3, later. For the reasons explained in that 

section, EPA believes there are little or no non-EGU reductions 

available at the cost thresholds used in this rule. Therefore, 

EPA believes it is reasonable at this time to use cost curves 

that include only EGU reductions. However, EPA is continuing to 

conduct analyses and believes that it will be necessary to 

further consider non-EGU emission reduction opportunities in 

future transport rules.
250

To develop cost curves, emissions available at various 

costs were assessed in 2012 for ozone season NOX and 2014 for 

annual NOX and SO2. As described in section V.C, EPA coordinated 

the deadlines for eliminating significant contribution and 

interference with maintenance with the NAAQS attainment 

deadlines for downwind states and determined that all 

significant contribution and interference with maintenance with 

respect to the 1997 and 2006 PM2.5 NAAQS must be eliminated by 

2014, or as expeditiously as practicable. The cost curves show, 

among other things, that the amount of emissions reductions that 

can be achieved for a given cost varies over 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 SO2 emissions (Boilermaker Labor Analysis and Installation 

Timing, USEPA, March 2005), 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 NOX. (Boilermaker Labor Analysis and 
251

Installation Timing, USEPA, March 2005) Unlike add-on pollution 

controls such as scrubbers and SCRs, EPA believes that low-NOX

burners could be installed by 2012. See TSD, “Installation 

Timing for Low NOX Burners,” in the docket for this rule. 

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 many more potential scenarios than the 

time- and resource-intensive more refined air quality modeling 

would permit. This tool assesses the impact that reductions at 

 

56 As is discussed in the RIA, EPA also used the CAMx model to 

perform air quality analysis of its proposed remedy to address 

significant contribution. Results from this modeling will not 

exactly correspond to results from the air quality tool both 

because the inputs to the air quality modeling are different and 

the sophisticated model more fully accounts for the complex air 

chemistry interactions. The full air quality modeling 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.
252

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 PM2.5 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 multi-factor 
253

assessment to identify which cost threshold57 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 NOX 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 

 

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.
254

emissions reductions cost curves developed in steps 1 and 2 

related to (1) air quality (e.g., points at which all areas 

(other than those with an unusually predominant local pollution 

problem) reach attainment and have maintenance fully addressed), 

and/or (2) cost (e.g., points at which significant reductions 

are available because a certain technology is widely deployed).

EPA identifies potential breakpoints and then uses a multifactor assessment to evaluate whether one or more of the 

potential breakpoints represent a reasonable cost at which to 

define significant contribution for some or all upwind states. 

The factors in this multi-factor assessment can be divided into 

two broad categories: those that focus on air 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 
255

cost per ton of technologies already widely deployed (similar to 

the highly-cost-effective criteria used in both the NOX 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 short-term solution and then switch to another longterm 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 

NOX SIP call and CAIR), are reasonable for upwind states from a 

cost standpoint. Higher cost per ton levels also may be 

reasonable for upwind states based on examination of air quality 

and cost factors. One reason is that achieving attainment and 

maintenance of the air quality standard may require controls in 
256

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 the previous step to determine, on a 

state-by-state basis, the amount of emissions that could be 

reduced at a specific cost. The results of this analysis are 

used to develop the state 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
257

The discussion that follows explains how the methodology 

described previously was applied to quantify significant 

contribution with respect to the 1997 and 2006 PM2.5 NAAQS and 

the 1997 ozone NAAQS. EPA also believes that the methodology 

proposed today could also be used to address transport concerns 

under other NAAQS, including revisions to the ozone and PM2.5 

NAAQS.

All of the air quality considerations included in the 

multi-factor assessment are based on analysis using the air 

quality assessment tool. EPA believes that it is appropriate to 

use this tool because of the advantages it has over more refined 

air quality modeling to perform analysis of a large number of 

scenarios very quickly (more refined air quality modeling can 

take several months, while multiple scenarios can be evaluated 

using the air quality 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 

PM2.5, the air quality assessment tool slightly over-predicts the 

air quality benefit of the proposed reductions. 

For this reason, EPA is also requesting comment on whether 

we should modify our conclusions regarding the amount of 

specific states' significant contribution and interference with 

maintenance; whether there are ways to use our air quality 
258

modeling in conjunction with the air quality assessment tool to 

carry out the significant contribution analysis in a way that 

would not extend the time needed to complete this rulemaking; 

and whether there are ways to improve the air quality assessment 

tool.

a. Specific Application to PM2.5

(1) Year for Quantifying Significant Contribution

EPA’s significant contribution analysis for PM2.5 used a 

multi-factor assessment to identify cost thresholds for 2014. 

EPA believes this is the most appropriate year to consider 

because it is consistent with attainment dates for both the 

annual and daily PM2.5 standards. Furthermore, EPA believes that 

2014 provides sources sufficient lead time 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 
259

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 SO2 and NOX to 

address transport related to PM2.5. 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 PM2.5 NAAQS, EPA developed cost 

curves showing the annual NOX and annual SO2 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 NOX, $5,000/ton for ozone season NOX, and $2,400/ton for 

SO2. For example, this means that EPA examined reductions of 

annual NOX that are available at a cost of $2,500 per ton or 
260

less. For SO2, the projected cost to reduce a ton of emissions 

considered is $2,400 or less.

Table IV.D-1 shows the annual NOX emissions from EGUs at 

various levels of control cost for 2014. 

Table IV.D-1 2014 Annual NOX Emissions from Electric Generating 

Units for each State in the Transport Region at Various Costs 

(2006 $) per Ton

(Thousand Tons)

Marginal Cost 

per Ton:

Base 

Case 

Level

$500 $1,500 $2,500

Alabama 119 62 62 50

Connecticut 8 8 8 8

Delaware 6 6 6 6

Florida 196 138 113 80

Georgia 48 46 45 45

Illinois 80 56 56 56

Indiana 201 114 114 107

Iowa 68 56 50 47

Kansas 79 38 36 35

Kentucky 149 72 72 71

Louisiana 46 37 37 28

Maryland 36 36 36 36

Massachusetts 13 13 13 13

Michigan 99 68 68 66

Minnesota 55 38 38 38

Missouri 83 82 61 55

Nebraska 53 34 28 28

New Jersey 27 23 23 20

New York 36 35 32 31

North 

Carolina 63 63 62 61

Ohio 165 104 98 88

Pennsylvania 205 123 122 86

South 

Carolina 48 36 36 35

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 
261

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 NOX

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 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 NOX SIP Call will provide an incentive to run 

many SCRs.

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 NOX

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 SO2 show the same effect as those for 

NOX (large emissions reductions at relatively low costs and 
262

additional reductions at relatively high costs) but the effect 

was not as pronounced. In 2014, more than 1,000,000 tons of SO2

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, later, shows that in 2014 there are increased 

SO2 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). 
263

Table IV.D-2 2014 SO2 Emissions from Electric Generating Units for each State in the 

Transport Region at Various Costs (2006$) per Ton 

(Thousand Tons)

Marginal Cost 

per Ton:

Base 

Case 

Level 

$100 $200 $500 $1,000 $1,400 $1,800 $2,000 $2,400 

Alabama 322 307 257 171 166 146 101 84 71

Connecticut 6 6 6 6 6 3 3 3 3

Delaware 8 9 9 9 9 9 9 8 8

Florida 195 178 171 117 113 111 79 74 70

Georgia 173 166 136 133 117 101 92 86 67

Illinois 200 185 165 165 164 165 161 155 143

Indiana 804 478 433 328 291 284 242 227 190

Iowa 164 140 130 106 105 104 102 101 70

Kansas 65 64 56 49 46 46 33 31 24

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
264

(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. 
265

The percent emissions reductions (and percent air quality 

improvement) that could be made by each upwind state in 2014 at 

different cost per ton levels are shown in Figures IV.D-1 

through IV.D-4, later. These figures show the percent reduction 

in SO2 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 SO2

emissions are linearly and directly proportional to downwind 

sulfate contributions. In other words, it is assumed that a 

specific percent reduction in SO2 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 SO2 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.
266

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 air downwind air quality. 

These changes apply to both the daily and annual PM2.5 NAAQS. 

While the pattern differs from state to state, many states see 

noticeable decreases in sulfate contribution for costs of 

$500/ton or less. Reductions in downwind contribution level 

off, then many states start to see an additional decrease in 

contribution at higher costs (in general about $1,500/ton).

Figure IV.D-1 Percent Reduction in Downwind SO2 Contribution as 

a Function of Cost in 2014 for DE, FL, KS, LA, MA and NE.

-10

0

10

20

30

40

50

60

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400

Marginal cost per ton (EGU SO2)

Percent reduction in 2014 contribution

DE

FL

KS

LA

MA

NE
267

Figure IV.D-2 Percent Reduction in Downwind SO2 Contribution as 

a Function of Cost in 2014 for AL, CT, MD, MN, NJ and SC.

-10

0

10

20

30

40

50

60

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400

Marginal cost per ton (EGU SO2)

Percent reduction in 2014 contribution

AL

CT

MD

MN

NJ

SC
268

Figure IV.D-3 Percent Reduction in Downwind SO2 Contribution as 

a Function of Cost in 2014 for IA, KY, NY, NC, OH, TN and VA.

0

10

20

30

40

50

60

70

80

90

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400

Marginal cost per ton (EGU SO2)

Percent reduction in 2014 contribution

IA

KY

NY

NC

OH

TN

VA
269

Figure IV.D-4 Percent reduction in downwind SO2 contribution as 

a function of cost in 2014 for GA, IL, IN, MI, MO, PA, WV and 

WI.

0

10

20

30

40

50

60

70

80

90

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400

Marginal cost per ton (EGU SO2)

Percent reduction in 2014 contribution

GA

IL

IN

MI

MO

PA

WV

WI

EPA also identified the overall air quality reductions 

projected by the air quality assessment tool at downwind 

nonattainment and maintenance receptor locations. As explained 

previously, the multi-factor assessment in step 3 analyzed the 

results from the downwind receptor analysis in step 2 for the 

annual and daily PM2.5 standards. Tables IV.D-3 and IV.D-4, 

later, show the air quality improvements in 2014 from the 

emissions reductions projected to occur at various costs. Table 

IV.D-4 also shows the average decrease in ambient daily PM2.5 for 

different sets of downwind sites for various reductions in SO2.
270

Table IV.D-3 Estimated Number of Nonattainment and/or 

Maintenance Monitor Sites in 2014 for Annual PM2.5 (as a Function 

of SO2 Cost-per-Ton Levels)58

2014 2014

Marginal 

Cost per 

Ton

Number of 

Remaining 

Nonattainment 

Monitor Sites

Number of 

Remaining 

Nonattainment and 

Maintenance 

Monitor Sites

$0 12 19

$100 3 6

$200 2 3

$300 2 3

$400 1 2

$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

 

58 NOx Reductions at $500/ton
271

Table IV.D-4 Daily Air Quality Impacts vs. SO2 Cost per Ton Levels in 2014 (also Assumes 

NOX Control Level at $500/ton). 

Marginal SO2 Cost per ton

↓

Number of 

Remaining 

Nonattainment 

and Maintenance 

Monitor Sites

Air Quality Improvement (Average ug/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.
272

A number of conclusions can be drawn from Tables IV.D3 and IV.D-4. Very low cost SO2 reductions result in 

significant air quality benefits.59 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 SO2 and 

NOX reductions in 2013 and 2014). The analysis also shows 

that higher cost reductions continue to provide downwind 

air quality improvements. 

(4) Identifying Cost Thresholds

(a) Considerations for 2014

For PM2.5, EPA considered three cost breakpoints for SO2

and one for NOX. 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 NOX, this point 

 

59 Measured in terms of downwind area nonattainment and/or 

maintenance concerns being addressed. This is also true in 

terms of improvements in air concentrations of PM2.5.
273

is similar to the $500/ton cost. For SO2, 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 SO2 EPA considered two 

breakpoints: 1) $2,000/ton SO2 and 2) $2,400/ton SO2. 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 SO2 and NOx Caps for Senator Carper – July 31, 

2009 – Appendix B, page 14), EPA believes that it is 

clearly possible for the power sector to install at least 

that quantity of scrubbers by 2014. The $2,400/ton SO2

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 
274

more than 1 percent60. As is explained later in this 

section, EPA believes that the monitor in Allegheny County 

that remains in non-attainment is in an area where the air 

quality problem is primarily local. Since EPA’s analysis 

suggests that the only remaining non-attainment problem is 

primarily local, EPA did not consider higher cost 

thresholds.

EPA did not consider additional cost thresholds for NOX

beyond $500/ton because there are minimal additional NOX

reductions until one considers cost levels higher than 

$2,400/ton, and SO2 reductions are generally more effective 

than NOX reductions at reducing PM2.5. EPA did not consider 

lower cost thresholds than $2,000/ton for SO2 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; 

 

60 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.
275

and costs of up to $2,000/ton of SO2 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 SO2 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 SO2, this cost per ton level is relatively low. 

A survey of the control options that EPA examined in the 

PM2.5 RIA shows that non-EGU SO2 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 
276

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 SO2. 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 
277

area is significantly affected by a large increment of 

local emissions from a sizable coke production facility and 

other nearby sources. (See 

http://www.epa.gov/pmdesignations/2006standards/final/TSD/t

sd_4.0_4.3_4.3.3_r03_PA_2.pdf). High concentrations of 

organic carbon indicate the unique local problem for this 

location.

Because the remaining PM2.5 problem is more local in 

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 

can be reduced for $2,000/ton in 2014 is an appropriate 

quantification of a state’s significant contribution, EPA 

considered whether any of these emissions reductions could 

be achieved prior to 2014. For the reasons that 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 SO2 controls (scrubbers) or post combustion NOX
278

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 SO2, reductions from operating 

existing scrubbers up to their design removal efficiencies 

and from the use of lower sulfur coals are possible by 

2012. For NOX, reductions from operating existing SCRs on a 

year-round basis and up to their design removal 

efficiencies and the installation of limited amounts of low 

NOX burners are possible by 2012. For this reason, EPA 

believes it is appropriate to require these emissions to be 

removed in 2012, consistent with the Act’s 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 less than $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 
279

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 1 states. Although states are linked to 

different sets of downwind receptors, our analysis 
280

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 approaches, 

support the decision to use uniform costs for a group of 

states. 

(d) Summary of PM2.5 cost threshold analysis

Summary of methodology. In summary, EPA determined 

that SO2 emissions that could be reduced for less than 

$2,000/ton in 2014 should be considered a state’s 

significant contribution, unless EPA determined that a 

lesser reduction would fully resolve the nonattainment 

and/or maintenance problem for all the downwind monitoring 

sites to which a particular state might be linked. For 

these “group 2 states” EPA is determining that a lesser 

reduction of SO2, based on the amount of SO2 reductions that 

can be reasonably achieved by 2012 is appropriate. EPA 

also determined that all states linked to downwind PM2.5

nonattainment and maintenance problems should be required 

to achieve those emissions reductions that can be 

reasonably achieved by 2012. Finally, EPA determined that 
281

all states linked to downwind PM2.5 nonattainment (see Table

IV.D-5) and maintenance problems should, by 2012, remove 

all NOX emissions that can be reduced for less than $500/ton 

in 2012. 

Table IV.D-5 States Covered for SO2 Group 1, SO2 Group 2, 

and NOX Annual

States Covered

SO2

Group 

1

SO2

Group 

2

NOX

Annual

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 √ √

Wisconsin √ √

TOTALS 15 13 28
282

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 

PM2.5 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 
283

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 PM2.5 standard, the air quality 

assessment tool projected that, after implementation of the 

proposed FIPs, only one area (Allegheny County, PA) would 

have a continuing NAAQS air quality problem under the 

maintenance criteria. The results of the refined air 

quality modeling are very similar. This modeling projects 

similar annual PM2.5 reductions in downwind states and 

projects that Allegheny County, PA would remain in 
284

nonattainment and that Birmingham, AL would exceed the 

threshold for “maintenance” by a slight amount (less than 

0.1 ug/m3). Given the unique local nature of the Allegheny 

County, PA receptor (see discussion previously), EPA does 

not believe 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 PM2.5 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 PM2.5 NAAQS in Birmingham. For these reasons, EPA 

does not believe that the more refined air quality modeling 

for the annual PM2.5 standard changes any of EPA’s 

conclusions with respect to reductions required to 

eliminate significant contribution and interference with 
285

maintenance with respect to this standard. EPA is, 

however, taking comment on whether Florida, the one group 2 

state that was identified as linked to Birmingham, should 

be moved from group 2 to group 1. EPA notes that no group 

2 states are linked to Allegheny County, PA.

For the 24-hour PM2.5 standard, the simplified air 

quality assessment tool results suggest that under EPA’s 

proposed FIPs, only one problem site, Allegheny County, PA, 

would remain. In contrast, the more refined CAMx air 

quality modeling results show a greater 24-hour PM2.5

problem, with 10 nonattainment and 4 maintenance areas. As 

described later, EPA is evaluating the impact of this 

refined air quality modeling on the methodology used and 

the conclusions it has reached regarding significant 

contribution and interference with maintenance with regard 

to the 24-hour PM2.5 NAAQS. 

EPA has completed some preliminary analysis of the 

difference between the air quality 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 
286

reflects the complex nature of the winter portion of the 

24-hour PM2.5 problem. Unlike summer days, for which 

sulfate is the dominant contributor to PM2.5, sulfate 

concentrations are typically a lesser contributor to the 

overall PM2.5 concentrations on winter days. Moreover, for 

winter days, reductions in this already reduced amount of 

sulfate appear to be less responsive to reductions in SO2

than for the summer days. That is, while for the summer a 

50 percent reduction in SO2 emissions would likely yield a 

nearly 50 percent reduction in sulfate concentrations, in 

the winter such a reduction in SO2 would reduce sulfate by 

less than 50 percent. Thus, EPA believes that more study 

of the winter portion of the problem is warranted to 

address the issues raised by the CAMx modeling. EPA 

believes it is important to understand the degree to which 

these winter exceedances are transport-related or locally 

generated, and the degree to which upwind states’ emissions 

of NOX, SO2, 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 SO2 resulting from the 

assessment tool should be raised to a higher cost cutoff. 
287

While the CAMx results may suggest that it would be 

appropriate to use a cutoff greater than $2,000/ton, the 

results do not suggest that the cutoff could be less than 

$2,000/ton. Instead, the results confirm the importance of 

achieving, at a minimum, all reductions available at the 

$2,000/ton cost threshold. 

Additionally, EPA is 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 maintenance problems after the implementation of the 

2012 reductions. 

EPA also notes that that during the winter, PM2.5

contains a larger nitrate component than in summer months. 

One reason for this is that some 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 
288

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 
289

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 SO2 emissions in those states. EPA’s modeling 

confirms this, projecting that, after the proposed rule is 

implemented in states regulated for SO2, 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 SO2 emissions increases 

over the base case and above 5,000 tons61. For reference, 

we also include the statewide 2012 base case emissions from 

all sources within the state. 

Table IV.D-6 Unregulated States with More than 5,000 

Tons of Projected SO2 Increases under the Proposed Transport 

Rule

State 2012 SO2 Increase 

from Base Case 

(thousand tons)

2012 SO2 Base Case 

Emissions from All 

Sources (thousand 

 

61 While Colorado is also a state that may see projected 

increases in emissions, it was not within the domain the 

EPA analyzed.
290

tons)

Arkansas 32 127

Mississippi 18 81

North Dakota 11 94

South Dakota 6 26

Texas 136 641

Further analysis with the air quality assessment tool 

indicates that these projected increases in the Texas SO2

emissions would increase Texas’s contribution to an amount 

that would exceed the 0.15 μg/m3 threshold for annual PM2.5. 

For this reason, EPA 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 PM2.5 standard, it 

may not fully address the 24-hour PM2.5 standard. Where 

this may be the case, as explained previously, EPA’s air 

quality modeling shows that the remaining component of 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, 
291

is quite different between summer and winter. Because of 

this, EPA is moving ahead with further efforts, before the 

final rule is published, to determine the extent to which 

this winter problem is caused by emissions transported from 

upwind states and, if this is the case, to identify the 

total amount of emissions that represents significant 

contribution and interference with maintenance. To the 

extent possible, EPA plans to finalize a rule that fully 

defines this amount. 

Based on the information that EPA currently has, EPA 

believes there are a number of possible outcomes of this 

further study. Possible outcomes include:

(1) Identification of the additional amount of SO2

emissions reductions needed to eliminate significant 

contribution and interference with maintenance from 

upwind states contributing to the residual 24-hour 

PM2.5 problem sites

2) Identification of the additional amount of NOX

emissions reductions needed to eliminate significant 

contribution and interference with maintenance from 

upwind states contributing to the residual 24-hour 

PM2.5 problem sites

3) Identification of another pollutant that should be 

considered part of significant contribution and 
292

interference with maintenance for states that 

contribute to the residual 24-hour PM2.5 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 SO2 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 SO2

emission reductions are required or that the amount of 

emissions of SO2 and NOX that it has proposed as 

significantly contributing to nonattainment are the 

appropriate amounts to address this winter portion of 

the problem, EPA intends to supplement today’s 

proposal and finalize a rule that would fully 

addresses emissions that significantly contribute to 

or interfere with maintenance of the 2006 daily PM2.5

standard.

To the extent that EPA determines that more NOX

reductions are needed or that reductions of another 

pollutant are needed, EPA believes that we could 
293

provide the greatest assistance to states in 

addressing transport by finalizing this rule quickly 

and promulgating a separate rule to achieve any 

necessary additional NOX reductions. This is because 

those emission 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 
294

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 PM2.5, 

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 all states “linked” to 

“serious area” locations for which 2012 is the latest ozone 

season prior to their attainment deadline, EPA believes 

that 2012 is the appropriate year for eliminating 

significant 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 
295

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.62 

EPA is concerned that the timing of this rule presents 

difficult challenges in eliminating significant 

contribution and interference with maintenance with regard 

to the 1997 ozone NAAQS by the attainment date. For states 

with a 2012 (or earlier) attainment date for which we 

project continuing ozone problems, we are concerned that 

strict adherence to a 2012 date for 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 

 

62 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.
296

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)63. 

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. 

 

63 In the case of PM2.5, under subpart I, areas can qualify 

for an extension beyond 5 years, to as many as 10 years, 

based on certain statutory criteria. 
297

If in determining upwind state reduction 

responsibilities EPA were to automatically assume that 

downwind states will attain on time despite pollution 

transport, this assumption would have the effect of 

absolving the upwind state of responsibility for any 

reductions in pollution transport that could not be 

achieved by the downwind area’s current attainment date. 

EPA does not believe this would be appropriate. This would 

transfer emissions control responsibility from the upwind 

state to the downwind state in any case when the area did 

not attain by its current attainment date, and could delay 

for years the date when the public would breathe air that 

meets health-based standards.

Accordingly, for all the reasons discussed 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 NOX limits (e.g., 

reflecting SCR) could conceivably be considered in a swift, 

subsequent rulemaking. 

One area in the eastern half of the U.S. covered by 

this proposal, Houston, is classified as “severe.” For 

Houston, it is relevant to consider both that (1) the 
298

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 NOX

Using IPM, EPA developed cost curves for 2012 for 

ozone season NOX, showing the ozone season (May-September) 

NOX 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 add-on equipment. Some 

highly effective and widely employed NOX control 
299

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 

install64, 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 NOX SIP Call) EPA identified potential 

reductions from the installation of some combustion 

controls/low NOX 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.

Table IV.D-7 2012 Ozone-season NOX Emissions from Electric 

Generating Units for each State at Various Costs (2006 $) 

per Ton (thousand tons)

Marginal 

Cost per 

Ton:

$0 $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

 

64 Estimate from EPA report, ‘‘Engineering and Economic 

Factors Affecting the Installation of Control Technologies 

for Multi-Pollutant Strategies,’’ CAIR docket no. OAR–2003–

0053–0106).
300

Maryland 14 14 14 14 14 14 14 14 14

Michigan 30 30 30 30 30 30 29 28 28

Mississippi 17 8 8 8 8 8 8 8 8

New Jersey 7 7 7 7 7 7 7 7 7

New York 16 16 16 16 16 16 16 16 16

North 

Carolina

27 27 27 27 27 27 27 27 27

Ohio 42 41 41 41 41 42 42 42 42

Oklahoma 43 27 27 27 27 26 26 26 26

Pennsylvania 51 51 51 51 50 50 50 50 48

South 

Carolina

16 16 16 15 15 15 15 15 15

Tennessee 12 12 12 12 12 12 12 12 12

Texas 79 67 67 67 67 66 66 66 66

Virginia 18 18 18 18 18 18 17 17 17

West 

Virginia

24 24 23 23 22 23 22 22 18

Total 746 648 632 628 625 622 620 618 609

As discussed in section IV.D.3 later, little or no 

ozone season NOX reductions are available for non-EGU 

sources from control measures costing less than $500/ton. 

Therefore EPA believes its cost curves, which include EGUs 

only, are complete up to $500/ton but are not complete at 

costs greater than $500/ton.

For this reason, we are not addressing in this 

proposal whether cost per ton levels higher than $500/ton 

are justified for some upwind states and downwind receptors 

for ozone purposes. However, we are presenting the 

information we have on potential EGU reductions at higher 

cost levels for informational purposes. EPA intends to 

develop similar emissions reductions and cost information 

for sources other than EGUs and, in a future rulemaking, to 
301

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 

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. 

Table IV.D-8 2014 Ozone-season NOX Emissions from Electric 

Generating Units for each State at Various Costs (2006$) 

per Ton (thousand tons)

Marginal 

Cost per 

Ton:

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $5,000 

Alabama 27 27 27 27 27 27 27 26 26

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
302

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 NOX reductions on downwind ozone 

concentrations. This air quality assessment tool assumes a 

linear relationship between the reduction in an upwind 

state’s ozone season NOX reductions and the reduction in 

that state’s contribution to downwind ozone levels. For 

example, if a given upwind state reduced its ozone season 

NOX emissions by 20 percent, the air quality assessment tool 

estimates that there would also be a 20 percent reduction 

in the state’s contribution to downwind ozone. Using this 
303

assessment tool, EPA projected the air quality impact of 

the emissions reductions at the $500/ton NOX 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 NOX 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.
304

Table IV.D-9 Estimated Number of Remaining Nonattainment 

or Nonattainment and Maintenance Monitor Sites in 2012 and 

2014 as a Function of Ozone-season NOx Cost per Ton Levels.

2012 2012 2014 2014

Margina

l Cost 

per Ton

Number of 

Remaining 

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

(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 
305

controls. Compared to NOX reduction levels determined to be 

highly cost effective in both the NOX SIP Call and the CAIR, 

$500/ton is a very low cost for requiring ozone season NOX

reductions, and reductions at this level show measurable 

downwind air quality benefit. EPA believes that $500/ton 

continues to be an extremely cost effective level for NOX

control relative to benchmarks provided by the cost per ton 

of NOX 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 NOX 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 NOX

controls for the NOX 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 
306

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 NOX 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. 
307

Thus, EPA believes that additional post-2012 controls, 

beyond the $500/ton reductions that are justified based on 

2012, are possibly warranted for states that are linked to 

Houston and Baton Rouge. (See also discussion later on the 

issue regarding New York City raised by air quality 

modeling results.)

(c) Proposed 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 
308

$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 NOX control costs, 

emissions reductions, and air quality impact information 

for NOX controls greater than $500/ton, and to examine facts 

involving Houston and Baton Rouge, to support a complete 

determination of 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 
309

proposal, EPA believes that any additional NOX 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 NOX 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 PM2.5, EPA has done additional 

refined air quality analysis of a 2014 scenario that 

assumes implementation of the proposed ozone season NOX

emissions reductions, that is, the reductions that would be 

achieved based on the $500/ton NOX cost threshold. This air 
310

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 required NOX

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 NOX emissions that could 

be reduced for less than $500/ton. The modeling also 

showed that the locations within the New York City 

nonattainment area would continue to have a 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 in nonattainment in light of 

historical year-to-year variability in ozone levels in the 

New York City area. For that reason, EPA is taking comment 

on whether it should consider and analyze the NOX 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 
311

whether and to what extent states linked to New York City, 

Houston, and Baton Rouge should be required to make 

additional NOX 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 SO2 and NOX emissions reductions necessary to 

eliminate at least part of each state’s significant 

contribution and to eliminate at least part of each upwind 

state’s interference with maintenance of the PM2.5 NAAQS. 

In addition, EPA discusses interim cost criteria for ozone. 

Consistent with these criteria, EPA does not believe that 

other source categories have emissions that are currently 

significantly contributing to nonattainment or interfering 

with maintenance of the 1997 and 2006 PM2.5 NAAQS. Thus, 

with respect to the 1997 and 2006 PM2.5 NAAQS, we are not 

proposing to include in the FIPs emissions reductions 

requirements for other source categories. 

(a) SO2 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 
312

the highest cost value necessary for SO2 to eliminate 

significant contribution and interference with maintenance. 

For SO2, 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 SO2 reductions for sources other than 

EGUs at less than $2,000/ton (in year 2006 $).

For the CAIR, EPA included a technical support 

document65 which noted that for SO2, 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 highest-emitting categories of non-EGU 

SO2 emissions are: (1) industrial, commercial, and 

institutional (ICI) boilers, (2) Portland cement 

manufacturing, (3) petroleum refining, and (4) sulfuric 

acid manufacturing.

 

65 Identification and Discussion of Sources of Regional Point 

Source NOX and SO2 emissions other than EGUs. EPA/OAQPS and 

CAMD. January 2004.
313

For ICI boilers, most of the SO2 emissions are from 

coal-fired boilers, and to a lesser degree from residual or 

distillate oil-fired boilers. Possible ways to reduce SO2

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 NESCAUM66 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 SO2 scrubbing to be 

between $2,211 - 6,917 per ton (in year 2003 $). The LADCO 

“white papers” discussion is available from the following 

website: 

http://www.ladco.org/reports/control/final_reports/identifi

 

66 Reference: NESCAUM Applicability and Feasibility of NOX, 

SO2, and PM Emissions Control Technologies for Industrial, 

Commercial, and Institutional (ICI)Boilers. NESCAUM, 

November 2008. pp. xvii, 3-12-13. 
314

cation_and_evaluation_of_candidate_control_measures_ii_june

_2006.pdf. 

For petroleum refining, the largest sources of SO2 

emissions are from catalytic cracking, sulfur recovery 

units, and process heaters. For each of the sources in the 

petroleum refining sector, EPA believes that SO2 controls 

less than $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 SO2

emissions reductions annually. Compliance with these 

agreements has already taken place at most affected 

refineries, and these reductions are generally reflected in 

our 2012 base case emissions inventory.67 

For sulfuric acid manufacturing, the SO2 emissions are 

related to the percent recovery of sulfuric acid product. 

Because the percent recovery is plant-specific, the 

available emissions reductions and the cost per ton of 

controls are highly variable. At the time of the CAIR, EPA 

made rough calculations that the then-existing 126,000 tons 

 

67 U.S. EPA. Petroleum Refinery National Priority Case 

Results. Available at

http://www.epa.gov/compliance/resources/cases/civil/caa/oil

/index.html. 
315

of SO2 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 SO2 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 SO2 reductions have taken 

place at 22 plants in the U.S. by 2012 as a result of 6 

settlement agreements.68 More than half of these plants are 

in states affected by this proposal.

This information shows that few if any SO2 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 SO2 reduction requirements 

for addressing PM2.5 transport for the proposed rule. EPA 

seeks comment on whether non-EGU emissions reductions 

should be required and on the specific control measures 

that would serve as the basis for those reductions. 

 

68 U.S. EPA. Acid Plant NSR Enforcement Priority. 

Available at 

http://www.epa.gov/compliance/civil/caa/acidplantnsr/index.html. 
316

Because sulfur content of both gasoline and diesel 

fuel are now subject to very stringent sulfur requirements, 

EPA believes there are no available on-road and nonroad 

engine measures to reduce mobile source SO2 at levels below 

$2,000/ton. 

b. NOX from Non-EGU Sources 

For NOX, the methodology described previously in 

section IV.D.2 requires all states linked to PM2.5

nonattainment and maintenance areas to ensure that 

emissions do not increase above 2009 levels. This 

translates into a cost cutoff of $500/ton. In addition, 

for ozone, EPA determined that a number of states can 

eliminate their significant contribution and interference 

with maintenance by installing controls at this same 

$500/ton cost threshold. 

For the CAIR, the technical support document69

evaluating non-EGU controls contained a discussion of nonEGU category contributions to the overall NOX 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 

 

69 Identification and Discussion of Sources of Regional 

Point Source NOX and SO2 emissions other than EGUs. 

EPA/OAQPS and CAMD. January 2004.
317

of non-EGU NOX controls done for the CAIR with a review of 

the year 2012 inventory. See TSD – “Non-EGU Emissions 

Reductions Cost and Potential.” The highest-emitting 

stationary source categories of non-EGU NOX emissions are: 

(1) stationary reciprocating internal combustion 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 information70 suggests that costs of various types 

of NOX controls are greater than this level for non-EGU 

sources such as ICI boilers, iron and steel mills, 

petroleum refineries71, glass manufacturing plants, and 

asphalt manufacturing plants. For industrial boilers, a 

recent report prepared by NESCAUM72 suggests NOX control 

costs are typically well above $500/ton for ICI boilers. 

 

70 Reference: Identification and Evaluation of Candidate 

Control Measures. Phase II Final Report. LADCO, June. 

2006. Appendix B. 

71 Reference: Assessment of Control Technology Options For 

Petroleum Refineries in the Mid-Atlantic Region. Final 

Report. MARAMA, January, 2007. p. 2-24. 

72 Reference: NESCAUM Applicability and Feasibility of NOX, 

SO2, and PM Emissions Control Technologies for Industrial, 

Commercial, and Institutional (ICI)Boilers. NESCAUM, 

November 2008. pp. xvii, 3-12-13. 
318

In addition, a recent report prepared by LADCO73 indicated 

NOX control costs are also well above $500/ton for glass 

manufacturing plants and asphalt manufacturing plants. 

For the NOX 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 NOX per day. For each of 

these categories regulated under the NOX SIP call, EPA 

believes there are no available control measures 

(especially that could be implemented by 2012) at less than 

the $500/ton. 

EPA has not identified further controls for stationary 

nonpoint sources or mobile source NOX measures that have 

costs less than $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 

 

73 Reference: Identification and Evaluation of Candidate 

Control Measures. Phase II Final Report. LADCO, June. 

2006. Appendix B. 
319

be eliminated. A state’s emissions budget is the quantity 

of emissions that would remain in that state from covered 

sources after elimination of that portion of each state’s 

significant contribution and interference with maintenance

that EPA has identified in today’s proposal, before 

accounting for the inherent variability in power system 

operations (see discussion of variability in section IV.F, 

later). The state emissions budget is a mechanism for 

converting the quantity of emissions that a state must 

reduce (i.e., the state’s significant contribution and 

interference with maintenance) into enforceable control 

requirements. In other words, it provides a quantity of 

emissions to use in developing a 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 fossil-fuel-fired generation was needed), the 

emissions that would remain after significant contribution 
320

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 SO2 and Annual NOX State Emissions Budgets for 

EGUs

For group 1 states required to make deeper emission 

reductions in 2014, EPA based each state’s 2014 budgets on 

the same projections from IPM that were used as inputs into 

the cost curves explained in section IV.D.2.a previously. 

For SO2, the values were taken from an IPM run requiring all 

SO2 reductions available at $2,000/ton. To account for 

potential interactions with NOX reductions, EPA also assumed 

NOX reductions at $500/ton. For group 2 states (and for the 

first phase 2012 budgets for sources required to make 

greater reductions in 2014), EPA took a different approach. 

These states are only required to make SO2 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 
321

covered by this rule in 2009,

74 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 NOX budgets, EPA used the same general 

methodology for all states that was used for the group 2 

states for SO2. The $500/ton cost threshold, that EPA has 

determined can be used to calculate the minimum significant 

contribution from upwind states linked to downwind 

nonattainment and maintenance areas, almost exclusively 

represents reductions from turning on SCR units. EPA 

believes that instead of defining the budgets based on IPM 

projections 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 

 

74 Even though allowance prices dropped significantly in 

2008 after the Court decision, most sources appear to have 

continued with the same reduction strategies.
322

input, historical emission rates and where new SCR units 

are expected between now and 2012, projected emission rates 

for those new SCR units. The emission budgets developed 

using the previous methodology are as follows in Table 

IV.E-1:

Table IV.E-1 – SO2 and Annual NOX State Emission Budgets for 

Electric Generating Units before Accounting for 

Variability75 (tons)

State SO2, 2012 

and 2013

SO2, 2014 

and Later

NOX 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

 

75 The impact of variability on the budgets is discussed in 

section IV.F, later.
323

State SO2, 2012 

and 2013

SO2, 2014 

and Later

NOX Annual, 

All Years

Virginia 72,595 40,785 29,581

West Virginia 205,422 119,016 51,990

Wisconsin 96,439 66,683 44,846

Total 3,893,870 2,500,003 1,376,312

For more detail on how the budgets were developed, see

the TSD: “State Budgets, Unit Allocations, and Unit 

Emissions Rates”.

2. Defining Ozone Season NOX State Emissions Budgets for 

EGUs

Ozone season NOX budgets were developed the same way as 

the annual NOX budgets were developed (explained in IV.E.1, 

previously). 

Table IV.E-2 – Ozone-season NOX State Emissions Budgets for 

Electric Generating Units Before Accounting for Variability 

(tons)

State

NOX Ozone 

Season, All 

Years

Alabama 29,738

Arkansas 16,660

Connecticut 1,315 

Delaware 2,450 

District of Columbia 105

Florida 56,939

Georgia 32,144

Illinois 23,570

Indiana 49,987

Kansas 21,433

Kentucky 30,908

Louisiana 21,220

Maryland 7,232 

Michigan 28,253

Mississippi 16,530
324

State

NOX Ozone 

Season, All 

Years

New Jersey 5,269 

New York 11,090

North Carolina 23,539

Ohio 40,661

Oklahoma 37,087

Pennsylvania 48,271

South Carolina 15,222

Tennessee 11,575

Texas 75,574

Virginia 12,608

West Virginia 22,234

Total 641,614

These budgets are based on a 5 month ozone season 

(May 1 through September 30). Consistent with the approach 

taken by the OTAG, the NOX SIP call, and the CAIR, we 

propose to define the ozone season, for purposes of 

emissions reduction requirements in this rule, as May 

through September. We recognize 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 
325

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 than 

projected in the average base case year occurs. 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 emission 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, 
326

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 

today’s proposal are eliminated. This occurs even when the 

emission 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 
327

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 emission 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 emission rate-based approach, 
328

emission rate limits could be developed that would meet the 

budget assuming a given pattern of operation for the 

affected units. If some of the units with higher emission 

rates actually operated more than projected, the state's 

actual emissions would be higher. In an interstate trading 

program, budgets could be developed that each state would 

be projected to meet in an average year. In some years, 

however, generation from units in one state may increase 

(with a corresponding increase in emissions), but because 

variability in a larger region is less significant than 

within a single state, the 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 
329

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 state-specific budgets absent 

variability, would ensure that total emissions do not 

increase. This remedy, therefore, ensures not only that 
330

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 1-year and 3-year limits are summarized later and 

described in more detail in the Power Sector Variability 

TSD.

Expected variability over a single year. EPA 

performed analyses using historical data to demonstrate 

that there is year-to-year variability in baseline 

emissions (even when emission rates for all units are held 

constant) and to quantify the magnitude of this 

variability. This year-to-year variability in emissions is 

reflected, in combination with other factors, in year-toyear 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 
331

of this analysis, therefore, are to determine the typical 

variability in emissions due to changes in generation and 

excluding variability in emissions due to changes in 

emission limits, and to set emissions criteria limits that 

can be used as part of a remedy to ensure that states are 

eliminating their significant contribution and 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 in emissions 

from the 99th percent confidence level and the mean. The 

approach resulted in a maximum allowable variability, in

tons, for each state. These values were then divided by 

the mean emissions values over the 7-year time period to 

yield a percentage variability value for each state. See

the Power Sector Variability TSD for details.

From the state-by-state tonnage and 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 
332

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 

only a constant percentage for all states that would 

satisfy the needs of smaller states with a greater range of 

emissions as a percentage would result in large states 

being allowed greater variability than needed. Conversely, 

using a constant tonnage that would satisfy the needs of 

larger states with greater range of emissions as a tonnage 

would result in small states being allowed greater 

variability then needed. To ensure adequate variability 

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 serves to minimize the total 

amount of emissions allowed under this combination 

variability limit approach. 

For the tonnage and percentage limit criteria, EPA

looked at a wide range of percentage and tonnage 
333

combinations, and chose for further investigation 

combinations that provided states sufficient variability 

limits (based on historic variability) and fit the 

requirement of minimizing the allowed emissions. Plants in 

states that were close to the variability limits were 

evaluated more closely to ensure the modeling reflected all 

controls known to operate. EPA believes that 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 SO2, an infrequently used unit that 

on average emitted 500 tons when it operated 10 percent of 

the time could increase its emissions to 1,500 tons by 

operating 30 percent of the time in a year when there is 

unusually high demand for that unit. That would result in 

a 20 percent increase in statewide emissions. In a much 

larger state, with a budget of 50,000 tons, such a change 

in operation would only lead to a 1 percent in change in 

statewide emissions.

For both annual NOX and SO2, the percentage variability 

limits are 10 percent of a state’s budget and the 
334

corresponding tonnage variability limits are 5,000 and 

1,700 tons for NOX and SO2, 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 SO2 budget is less than 1,700 tons, so 

Connecticut received a 1-year 1,700 ton variability limit 

for its EGU SO2 emissions. EGU sources in Connecticut could 

emit up to the state’s SO2 budget plus the variability limit 

of an additional 1,700 tons of SO2 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 
335

emissions over similar time periods, and to establish state 

budgets with variability limits that ensure that the 

significant contribution and interference with maintenance 

that EPA has identified in today’s notice be eliminated. 

While the year-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 
336

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 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-

 

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.
337

specific emissions budgets with variability limits. EPA 

calculated state budgets with both 1-year and 3-year 

variability limits.

Table IV.F-1 shows proposed variability limits by 

state on SO2 emissions for 2014 and later. Table IV.F-2 

shows proposed variability limits by state on NOX 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 NOX annual and SO2, the 

percentage limits calculated using this alternative 

methodology are 25 and 32 percent of a state’s budget, 

respectively. Under this alternative calculation method, a 

state’s variability limit would be no lower than 10 percent 

of its budget and no higher than 25 or 32 percent, for NOX

and SO2, 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.
338

For instance, although Connecticut’s proposed 1-year

variability limit of 1,700 tons is greater than 10 percent 

of its SO2 budget of 3,059 tons (306 tons), it is also 

greater than 32 percent of the budget (979 tons). 

Therefore, under this alternative calculation method, 

Connecticut’s 1-year SO2 variability limit would be 979 tons 

(32 percent of the state’s SO2 budget). Similarly, for 

annual NOX, while Connecticut’s proposed 1-year variability 

limit of 5,000 tons is greater than 10 percent of its NOX

annual budget of 2,775 (278 tons), it is greater than 25 

percent of the budget (694 tons). Therefore, under this 

alternative approach, Connecticut’s 1-year annual NOX

variability limit would be 694 tons. Tables IV.F-1 through

IV.F-3 show the variability limits under the proposed and 

alternative calculation methods. See the Power Sector 

Variability TSD in the docket for this rule for more 

details.

Table IV.F-1 – Variability Limits on SO2 Annual 

Emissions for 2014 and Later for Electric Generating Units

(Tons)

State

SO2 Annual 

Emissions 

Budget

Proposed Alternative

1-year 

Limit

3-year 

Average 

Limit

1-year 

Limit

3-year 

Average 

Limit

Alabama 161,871 16,187 9,346 16,187 9,346

Connecticut 3,059 1,700 981 979 565

Delaware 7,784 1,700 981 1,700 981

District of Columbia 337 1,700 981 108 62

Florida 161,739 16,174 9,338 16,174 9,338

Georgia 85,717 8,572 4,949 8,572 4,949

Illinois 151,530 15,153 8,749 15,153 8,749
339

State

SO2 Annual 

Emissions 

Budget

Proposed Alternative

1-year 

Limit

3-year 

Average 

Limit

1-year 

Limit

3-year 

Average 

Limit

Indiana 201,412 20,141 11,629 20,141 11,629

Iowa 86,088 8,609 4,970 8,609 4,970

Kansas 57,275 5,727 3,307 5,727 3,307

Kentucky 113,844 11,384 6,573 11,384 6,573

Louisiana 90,477 9,048 5,224 9,048 5,224

Maryland 39,665 3,967 2,290 3,967 2,290

Massachusetts 7,902 1,700 981 1,700 981

Michigan 155,675 15,568 8,988 15,568 8,988

Minnesota 47,101 4,710 2,719 4,710 2,719

Missouri 158,764 15,876 9,166 15,876 9,166

Nebraska 71,598 7,160 4,134 7,160 4,134

New Jersey 11,291 1,700 981 1,700 981

New York 42,041 4,204 2,427 4,204 2,427

North Carolina 81,859 8,186 4,726 8,186 4,726

Ohio 178,307 17,831 10,295 17,831 10,295

Pennsylvania 141,693 14,169 8,181 14,169 8,181

South Carolina 116,483 11,648 6,725 11,648 6,725

Tennessee 100,007 10,001 5,774 10,001 5,774

Virginia 40,785 4,078 2,355 4,078 2,355

West Virginia 119,016 11,902 6,871 11,902 6,871

Wisconsin 66,683 6,668 3,850 6,668 3,850

Total 2,500,003

Proposed 1-year variability limits are the larger of (1) 1,700 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 32 percent of the state's budget. If 1,700 

tons is greater than 32 percent of the state's budget, the state's 

limit is set at 32 percent of its budget. If 1,700 tons is less than 

10 percent of the state's budget, the state's limit is set at 10 

percent of its budget.

Table IV.F-2 – Variability Limits on NOX Annual 

Emissions for 2014 and Later for Electric Generating Units

(Tons)

State

NOX Annual 

Emissions 

Budget

Proposed Alternative

1-year 

Limit

3-year 

Average 

Limit

1-year 

Limit

3-year 

Average 

Limit

Alabama 69,169 6,917 3,993 6,917 3,993

Connecticut 2,775 5,000 2,887 694 401

Delaware 6,206 5,000 2,887 1,552 896

District of Columbia 170 5,000 2,887 43 25

Florida 120,001 12,000 6,928 12,000 6,928

Georgia 73,801 7,380 4,261 7,380 4,261

Illinois 56,040 5,604 3,235 5,604 3,235

Indiana 115,687 11,569 6,679 11,569 6,679

Iowa 46,068 5,000 2,887 5,000 2,887
340

State

NOX Annual 

Emissions 

Budget

Proposed Alternative

1-year 

Limit

3-year 

Average 

Limit

1-year 

Limit

3-year 

Average 

Limit

Kansas 51,321 5,132 2,963 5,132 2,963

Kentucky 74,117 7,412 4,279 7,412 4,279

Louisiana 43,946 5,000 2,887 5,000 2,887

Maryland 17,044 5,000 2,887 4,261 2,460

Massachusetts 5,960 5,000 2,887 1,490 860

Michigan 64,932 6,493 3,749 6,493 3,749

Minnesota 41,322 5,000 2,887 5,000 2,887

Missouri 57,681 5,768 3,330 5,768 3,330

Nebraska 43,228 5,000 2,887 5,000 2,887

New Jersey 11,826 5,000 2,887 2,957 1,707

New York 23,341 5,000 2,887 5,000 2,887

North Carolina 51,800 5,180 2,991 5,180 2,991

Ohio 97,313 9,731 5,618 9,731 5,618

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 5,000 2,887

Virginia 29,581 5,000 2,887 5,000 2,887

West Virginia 51,990 5,199 3,002 5,199 3,002

Wisconsin 44,846 5,000 2,887 5,000 2,887

Total 1,376,312

Proposed 1-year variability limits are the larger of (1) 5,000 

tons or (2) 10 percent of the state's budget. 3-year limits are 

the 1-year limits divided by the square root of three.

The alternative 1-year variability limit is 5,000 tons as long as 

that amount is between 10 and 25 percent of the state's budget. 

If 5,000 tons is greater than 32 percent of the state's budget, 

the state's limit is set at 25 percent of its budget. If 5,000 

tons is less than 10 percent of the state's budget, the state's 

limit is set at 10 percent of its budget.

The NOX ozone season variability limits have been 

calculated based on five months of data corresponding to 

the May through September ozone season. EPA is proposing 

to use the same approach to calculate ozone season limits 

that the Agency used to calculate the proposed SO2 and NOX

annual variability limits described earlier in this 

section, but adjusted to reflect the ozone season data.
341

Using that approach, the resulting ozone season 1-year 

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 SO2 and NOX annual limits described 

previously. EPA determined the 3-year variability limits 

as the 1-year limits divided by the square root of three, 

the same approach used for the SO2 and NOX annual limits. 

The NOX 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 NOX 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 NOX emissions 

projections in the IPM modeling, but the differences are 

expected not to make a noticeable impact in the overall air 

quality results. 
342

As with the SO2 and NOX annual variability limits, EPA 

also calculated NOX 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 NOX ozone season, the 

percentage limit ceiling would be 31 percent of a state’s 

budget. The NOX ozone season limits resulting from this 

approach are also shown in Table IV.F-3.

EPA requests comments on the NOX ozone season limits 

shown in Table IV.F-3.

Table IV.F-3 – Variability Limits on NOX Ozone 

Emissions for 2014 and Later for Electric Generating Units

(Tons)

State

NOX 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 1,212 408 235

Delaware 2,450 2,100 1,212 760 438

District of Columbia 105 2,100 1,212 33 19

Florida 56,939 5,694 3,287 5,694 3,287

Georgia 32,144 3,214 1,856 3,214 1,856

Illinois 23,570 2,357 1,361 2,357 1,361

Indiana 49,987 4,999 2,886 4,999 2,886

Kansas 21,433 2,143 1,237 2,143 1,237

Kentucky 30,908 3,091 1,784 3,091 1,784

Louisiana 21,220 2,122 1,225 2,122 1,225

Maryland 7,232 2,100 1,212 2,100 1,212

Michigan 28,253 2,825 1,631 2,825 1,631

Mississippi 16,530 2,100 1,212 2,100 1,212

New Jersey 5,269 2,100 1,212 1,633 943

New York 11,090 2,100 1,212 2,100 1,212

North Carolina 23,539 2,354 1,359 2,354 1,359

Ohio 40,661 4,066 2,348 4,066 2,348

Oklahoma 37,087 3,709 2,141 3,709 2,141
343

State

NOX Ozone 

Season 

Emissions 

Budget

Proposed Alternative 

1-year 

Limit

3-year 

Average 

Limit

1-year 

Limit

3-year 

Average 

Limit

Pennsylvania 48,271 4,827 2,787 4,827 2,787

South Carolina 15,222 2,100 1,212 2,100 1,212

Tennessee 11,575 2,100 1,212 2,100 1,212

Texas 75,574 7,557 4,363 7,557 4,363

Virginia 12,608 2,100 1,212 2,100 1,212

West Virginia 22,234 2,223 1,284 2,223 1,284

Total 641,614

Proposed 1-year variability limits are the larger of (1) 2,100 

tons or (2) 10 percent of the state's budget. 3-year limits are 

the 1-year limits divided by the square root of three.

The alternative 1-year variability limit is 2,100 tons as long as 

that amount is between 10 and 31 percent of the state's budget. 

If 2,100 tons is greater than 31 percent of the state's budget, 

the state's limit is set at 31 percent of its budget. If 2,100 

tons is less than 10 percent of the state's budget, the state's 

limit is set at 10 percent of its budget.

As discussed in section V.D, the proposed FIPs would 

apply the 1-year variability limits commencing in 2014 and 

the 3-year variability limits commencing in 2016, noting 

that application of the 3-year average limits in 2016 would 

serve to limit each state’s emissions in 2014 and 2015. 

The Agency also requests comment on whether the remedy in 

the proposed FIPs should be modified so that the limits 

would apply starting in 2012 instead of 2014. In addition, 

the direct control remedy option on which EPA requests 

comments includes assurance provisions based on these 

variability limits that would apply starting in 2012. 

Thus, EPA also explains later 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 
344

for 2014 and later in Tables IV.F-1, IV.F-2, and IV.F-3 for 

all state budgets except for the SO2 budgets for the 15 

states comprising the stringent SO2 tier (“group 1”), which 

have different SO2 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 SO2 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 SO2 group 1 

states, which have different SO2 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 

SO2 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 SO2 budgets. The 2012 and 2013 1-year
345

limits on SO2 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 SO2 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 

SO2 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.F3.

For an alternative approach where variability limits 

start in 2012 instead of 2014, EPA considered – instead of 

two-year average limits on SO2 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 SO2 budgets in 2012 and 

2013 than in 2014 and beyond, calculation of the 3-year

average limits to apply in years spanning the two budget 

levels is less straightforward. EPA analyzed this 
346

alternative method for the 15 SO2 group 1 states and 

compared results to the results using the two-year average 

limits in 2012 and 2013 for these states, and determined 

that the two-year average approach is reasonable. See the 

Power Sector Variability TSD for more information.

 Table IV.F-4 includes 1-year and two-year 

variability limits calculated according to the proposed

methodology. The 2-year limits are the 1-year limits 

divided by the square root of two. The table does not 

include separate columns with variability limits calculated 

according to the alternative calculation method (described 

previously) because for the SO2 budgets in Table IV.F-4 the 

alternative calculation method would yield identical 

results to the proposed method. The Power Sector 

Variability TSD contains more details on the variability 

limits. 

Table IV.F-4 – 2012–2013 One- and Two-Year Variability 

Limits on SO2 Emissions for Group 1 States for Electric 

Generating Units (Tons)

State

SO2 Annual 

Emissions 

Budget

1-year Limit Two-year 

Average Limit

Georgia 233,260 23,326 16,494

Illinois 208,957 20,896 14,775

Indiana 400,378 40,038 28,311

Iowa 94,052 9,405 6,651

Kentucky 219,549 21,955 15,524

Michigan 251,337 25,134 17,772

Missouri 203,689 20,369 14,403

New York 66,542 6,654 4,705
347

North Carolina 111,485 11,148 7,883

Ohio 464,964 46,496 32,878

Pennsylvania 388,612 38,861 27,479

Tennessee 100,007 10,001 7,072

Virginia 72,595 7,259 5,133

West Virginia 205,422 20,542 14,526

Wisconsin 96,439 9,644 6,819

1-year variability limits calculated by the proposed method are 

the larger of (1) 1,700 tons or (2) 10 percent of the state's 

budget. Two-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 32 percent of the state's budget. 

If 1,700 tons is greater than 32 percent of the state's budget, 

the state's limit is set at 32 percent of its budget. If 1,700 

tons is less than 10 percent of the state's budget, the state's 

limit is set at 10 percent of its budget. The alternative 

calculation method would yield identical limits to the limits 

determined using the proposed method for the budgets in Table 

IV.F-4.

3. Summary of Emissions Reductions Across All 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.

Table IV.F-5 – Projected SO2 and NOX Electric Generating 

Unit Emissions Reductions in Covered States with the 

Transport Rule Compared to Base Case without Transport Rule 

or CAIR (Million Tons) 

2012

Base Case

Emissions

2012 

Transport 

Rule 

Emissions

2012 

Emissions 

Reductions

2014

Base Case 

Emissions

2014 

Transport 

Rule 

Emissions

2014

Emissions 

Reductions
348

SO2 8.4 3.4 5.0 7.2 2.6 4.6

Annual 

NOX

2.0 1.3 0.7 2.0 1.3 0.7

Ozone 

Season 

NOX

0.7 0.6 0.1 0.7 0.6 0.1

Note: Emissions differ from emissions budgets due to banking

Table IV.F-6 – Projected SO2 and NOX Electric Generating 

Unit Emissions Reductions in Covered States with the 

Transport Rule Compared to 2005 Actual Emissions (Million 

Tons)

2005 

Actual 

Emissions

2012 

Transport 

Rule

Emissions

2012 

Emissions

Reductions 

from 2005

2014 

Transport 

Rule

Emissions

2014

Emissions

Reductions 

from 2005

SO2 8.9 3.4 5.5 2.6 6.3

Annual 

NOX

2.7 1.3 1.4 1.3 1.4

Ozone 

Season 

NOX

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 D.C. Circuit. As discussed in section III 

previously, the D.C. Circuit has issued two significant 

decisions addressing the requirements of 

110(a)(2)(D)(i)(I). The first opinion largely upheld the 

NOX SIP Call, Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 
349

2000), and the second found significant flaws in the CAIR, 

North Carolina v. EPA, 531 F.3d. 896 (D.C. Cir. 2008). In 

both cases, the Court considered aspects of the methodology 

used by EPA to identify emissions that, pursuant to 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 used for this proposed rule 

relies on state-specific data to analyze each individual 

state’s significant contribution, uses air quality 

considerations in addition to cost considerations to 

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 
350

‘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 the region, EPA determines, on a 

state-by-state basis what reductions could effectively be 

achieved by sources in that state. EPA’s new approach does 

not, as the CAIR methodology did, establish a regional cap 

on emissions that 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 
351

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 SO2 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 
352

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 NOX

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 
353

considers the reasonableness of possible cost thresholds as 

part of a multi-factor analysis.

In addition, the methodology used in this rulemaking 

gives independent meaning to the interfere with maintenance 

prong of section 110(a)(2)(D)(i)(I). In North Carolina, 

the Court concluded that CAIR improperly “gave no 

independent significance to the ‘interfere with 

maintenance’ prong of section 110(a)(2)(D)(i)() to 

separately identify upwind sources interfering with 

downwind maintenance.” North Carolina, 531 F.3d at 910. 

EPA rectified this flaw in this rulemaking by separately 

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 PM2.5, this approach identified 16 maintenance sites 

in addition to the 32 nonattainment sites identified in the 

analysis of nonattainment receptors. For 24-hour PM2.5 this 

approach identified 38 maintenance sites in addition to the 

92 nonattainment sites identified in the analysis of 
354

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 PM2.5 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.
355

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 ug/m3), 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 NOX 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 
356

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 NOX SIP 

Call programs.

A. Pollutants included in this proposal

In this action, EPA is proposing FIPs to directly 

regulate upwind emissions of SO2 and NOX because of their 

impact on downwind states’ ability to attain and maintain 

the PM2.5 NAAQS. EPA is also proposing to regulate upwind 

emissions of NOX 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
357

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 SO2, NOX, and ozone season NOX. See

section V.D.4., later, for a detailed description of the 

proposed applicability requirements.77

Electric generating units are important sources of SO2

and NOX 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 SO2 emissions and about 20 percent of the

total man-made NOX emissions in the group of 32 states that 

would be affected by this rule (see Table III.A-1 in 

section III for lists of states).78

 

77 Certain non-EGUs and smaller EGUs were included in the 

CAIR NOX ozone season program in some CAIR states. EPA 

proposes that such units would not be covered by the 

Transport Rule requirements; see section V.F in this

preamble for further discussion of these units.

78 Emissions estimates are based on the 2012 baseline 

projections described in section IV in this preamble.
358

EPA has previously conducted extensive analyses of the 

cost and emissions impacts of SO2 and NOX reduction policies 

on the power sector using the Integrated Planning Model 

(IPM). Examples include EPA’s IPM analyses of a number of 

multi-pollutant bills, including the Clean Air Planning Act 

(S.843 in 108th Congress), the Clean Power Act (S.150 in 

109th Congress), the Clear Skies Act of 2005 (S.131 in 

109th Congress), the Clear Skies Act of 2003 (S.485 in 

108th Congress), and the Clear Skies Manager's Mark (of 

S.131). EPA also analyzed several power sector multipollutant scenarios in July 2009 at the request of Senator 

Tom Carper. These analyses are on EPA’s website at: 

(www.epa.gov/airmarkets/progsregs/cair/multi.html). EPA’s 

IPM analysis for CAIR is another example: 

(www.epa.gov/airmarkets/progsregs/epa-ipm/cair/index.html).

Based on these analyses, EPA believes that there exist 

reasonable means for EGUs to make substantial reductions in 

emissions of SO2 and NOX. EPA also believes that, at this 

time, EGUs can reduce SO2 and NOx emissions more costeffectively 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 SO2 and NOX emissions from EGUs in the FIPs in 

this proposed rule. EPA requests comments on these 
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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 PM2.5

In the proposed FIPs to address the section 

110(a)(2)(D)(i)(I) requirements with respect to the 1997 

and 2006 PM2.5 standards, EPA proposes to regulate only 

emissions from EGUs. As discussed previously in section 

IV.D, EPA’s review of the costs of EGU and non-EGU controls 

resulted in a conclusion that substantial SO2 and NOX

reductions from EGU are available at a cost per ton that is 

lower than the cost per ton of non-EGU controls. Other 

analyses discussed in section IV.D 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 PM2.5 NAAQS 

in downwind areas. This same section explains that EGU 

reductions substantially address eliminating the quantity 

 

79 See section IV.D.4 for discussion of non-EGUs that were 

included in CAIR NOX ozone season trading program.
360

of emissions identified by EPA as significantly 

contributing to or interfering with maintenance of the 2006 

PM2.5 NAAQS, and this same section explains the need for EPA 

to further analyze remaining winter PM2.5 exceedances. This 

conclusion does not, in any way, address whether a FIP 

promulgated by EPA or SIPs promulgated by the states should 

include reductions from non-EGU sources in order to 

eliminate significant contribution and interference with 

maintenance for any other NAAQS, including the 1997 ozone 

NAAQS and future NAAQS for PM2.5. 

b. Why EPA Does Not Propose to Require Reductions From 

Other Source Categories to Address Transport Requirements 

for Ozone

In the FIPs for this proposed rule, EPA is only 

proposing to require reductions from EGUs to address 

emissions from those source categories that significantly 

contribute to or interfere with maintenance of the 1997 

ozone NAAQS. As discussed previously in section IV.D, 

EPA’s review of the costs of EGU and nonEGU controls 

resulted in a conclusion that significant NOX emissions 

reductions from EGU are available at a cost per ton that is 

lower than the cost per ton of nonEGU NOX controls. The 

same section also explains the need for EPA to further 

analyze whether fully addressing upwind state 
361

responsibilities to reduce NOX emissions that contribute to 

downwind nonattainment and maintenance problems requires 

additional reductions at higher cost per ton, which again

would involve analysis of potential EGU and non-EGU 

reductions and costs. EPA will be moving forward to 

complete its assessment of pollution transport for the 1997 

ozone NAAQS as soon as possible. 

For future ozone and PM2.5 NAAQS, EPA intends to 

quantify the emissions reductions needed 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. 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.
362

1. Date for Prohibiting Emissions that Significantly 

Contribute or Interfere with Maintenance of the PM2.5 NAAQS 

For all areas designated as nonattainment with respect 

to the 1997 PM2.5 NAAQS, the SIP deadline for attaining that 

standard must be as expeditious as practicable but no later 

than April 2010, with a possible extension to no later than 

April 2015. Many areas have already come into attainment 

by the April 2010 deadline due in part to reductions 

achieved under CAIR. Because the 2010 deadline will have 

passed before the Transport Rule is finalized, we decided 

to coordinate the deadline for eliminating significant 

contribution under this rule with respect to the 1997 PM2.5

NAAQS with the April 2015 deadline that applies to areas 

that will need an extension of the April 2010 deadline. 

For all areas designated as nonattainment with respect to 

the 2006 24-hour PM2.5 NAAQS, the attainment deadline must be 

as expeditious as practicable but no later than December

2014 with a possible extension to as late as December 2019. 

Upwind emissions reductions achieved by the 2014 

emissions year will help areas that failed to meet the 

April 2010 deadline, to meet the April 2015 deadline for 

the 1997 PM2.5 NAAQS. These reductions will also help areas 

meet the December 2014 attainment deadline with respect to 
363

the 2006 PM2.5 NAAQS. Any areas not meeting that deadline, 

can request a 5 year extension to December 2019.

Further, a deadline of January 1, 2014 also provides 

adequate and reasonable time for sources to plan for 

compliance with the Transport Rule and install any 

necessary controls. EPA believes that this deadline is as 

expeditious as practicable for the installation of the 

controls needed for compliance (see further discussion in 

section IV.D).

2. Date for Prohibiting Emissions that Significantly 

Contribute or Interfere with Maintenance of the 1997 ozone 

NAAQS

Ozone nonattainment areas must attain permissible 

levels of ozone “as expeditiously as practicable,” but no

later than the date assigned by EPA in the ozone 

implementation rule (40 CFR part 51). The areas designated 

nonattainment in 2004 with respect to the 1997 8-hour ozone 

NAAQS in the eastern United States were assigned maximum 

attainment dates 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 
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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 

emission levels achieved by CAIR. Instead, it is the 

emission reduction 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 
365

require an initial phase of reductions by 2012 which would 

ensure that existing and planned SO2 and NOX 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 (D.C. 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 NOX 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 

also coordinated and the requirement that states attain the 

NAAQS as expeditiously as practicable. 

The 2014 deadline for compliance with the limits on 

annual NOX and annual SO2 emissions is coordinated with the 

April 2015 maximum attainment deadline for areas that 

received the maximum 5-year extension of the 5-year 

attainment deadline for the 1997 PM2.5 NAAQS (taking into 

account the need for reductions by 2014 to demonstrate 
366

attainment by April 2015). This 2014 compliance deadline 

is also consistent with December 2014 attainment deadline 

(5 years from designation, in the absence of an extension) 

for areas designated nonattainment for the 2006 PM2.5 NAAQS. 

Areas unable to meet this 2014 deadline may seek a maximum 

5-year extension to 2019. 

In addition, the 2012 compliance deadline for the 

first-phase of annual NOX and annual SO2 emission reductions 

will assure the reductions are achieved as expeditiously as 

practicable. EPA established the interim 2012 compliance 

deadline for annual NOX and annual SO2 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 SO2 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.
367

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 areas80.

EPA expects to finalize revised NAAQS for ozone in 

August 2010. After the NAAQS are finalized, EPA will be 

able to identify areas that are expected to have difficulty 

attaining and maintaining that standard, and evaluate and 

analyze the impact of upwind state emissions on those 

 

80 This proposed cumulative, seasonal standard is 

expressed as an annual index of the sum of weighted hourly 

concentrations, cumulated over 12 hours per day (8:00 am to 

8:00 pm) during the consecutive 3-month period within the O3

season with the maximum index value, set at a level within 

the range of 7 to 15 ppm-hours. 
368

standards. EPA has already begun the technical 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 PM2.5 NAAQS. This review is scheduled for 

completion in July 2011. EPA plans to conduct background 

technical analyses so that EPA will be prepared to move 

quickly, if necessary, with a transport rule related to any 

revised PM2.5 NAAQS.
369

D. Implementing Emissions Reductions Requirements

In this rule, EPA is proposing FIPs to eliminate the 

significant contribution and interference with maintenance 

EPA has identified in today’s action. We are proposing one 

“remedy” option to implement the necessary emissions

reductions and taking comment on two other options. Before 

presenting these options we briefly summarize the 

approaches used in the NOX SIP call and CAIR.

1. Approaches taken in NOX SIP call and CAIR

In the NOX 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 NOX SIP call provided an ozone-season NOX

trading program and addressed the requirements of the ozone 

NAAQS only. The CAIR provided SO2, annual NOX, and ozoneseason NOX trading programs, and addressed both the 1997 

ozone and the 1997 PM2.5 NAAQS.

NOX SIP Call approach. The NOX SIP call proposed a 

regional cap and trade program as a way to make costeffective NOX reductions. Created after years of scientific 

research and air quality data analyses showed that upwind 
370

NOX emissions can contribute significantly to ozone 

nonattainment in downwind states, the NOX Budget Trading 

Program (NBP) followed several other major efforts to 

reduce NOx from large, stationary sources. These 

initiatives included the Acid Rain Program, OTC NOX 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, NOX, 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 NOX 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 NOX

emissions that significantly contribute to downwind air 

quality problems. EPA established statewide NOX emissions 

budgets for the affected states. States had the 

flexibility to adopt the appropriate mix of controls for 

their state to meet the NOX emissions reductions 

requirements of the SIP call.
371

In the final regulation, EPA offered to administer a 

multi-state NOX Budget Trading Program for states affected 

by the NOX SIP call. The NOX 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 NOX emissions. The cap was the sum of the 

state emissions budgets established by EPA under the NOX 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 NOX

allowance market enabled sources to trade (buy and sell) 

allowances throughout the year. Sources could reduce NOX

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 NOX emissions (each allowance represents one ton of 

NOX emissions). This process is called annual 

reconciliation. If a source did not have enough allowances 

to cover its emissions, EPA automatically deducted 

allowances from the following year’s allocation at a 3:1 

ratio. If a source had excess allowances because it re-
372

duced emissions beyond required levels, it could sell the 

unused allowances or bank (save) them for use in a future 

ozone season. To accurately monitor and report emissions, 

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 NOX SIP call cap and trade program was a way to 

make cost-effective NOX reductions. Under the NOX SIP call, 

states had the flexibility to determine the mix of controls 

to meet their emissions reductions requirements. However, 

the rule provides that if the SIP controls EGUs, then the 

SIP must establish a budget, or cap, for EGUs. The EPA 

recommended that each state authorize a trading program for 

NOX emissions from EGUs. Each of the states required to 

submit a NOX SIP under the NOX 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 NOX SIP call cap and trade 

program, modeled closely after the OTC NOX Budget Program 
373

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 PM2.5 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 SO2

and/or NOX. Reducing upwind precursor emissions helps the 

downwind PM2.5 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 SO2 trading 

program in Title IV of the CAA and the NOx Budget Trading 

Program in the NOX SIP call. CAIR required implementation 

of emissions reductions requirements for SO2 and NOX be 

implemented in two phases. The first phase of NOX

reductions started in 2009 (covering 2009-2014) and the 

first phase of SO2 reductions began in 2010 (covering 2010-

2014); the second phase of reductions for both NOX and SO2
374

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 SO2 and NOX emissions for 

PM2.5, and seasonal NOX 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 NOX SIP call cap and trade program to 

be replaced by the CAIR ozone season NOX 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 NOX SIP Call and the CAIR were 

brought before the U.S. Court of Appeals for the D.C. 

Circuit. In Michigan v. EPA, 213 F.3d 663, the Court 

largely upheld the NOX 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 
375

of amount of contribution, reduce their NOX by an amount 

achievable with ‘highly cost-effective controls.” Id. at 

679. EPA’s approach, Petitioners first alleged, was 

irrational because it did not take into account differences 

in individual states’ respective contributions to downwind 

nonattainment. Both small and large contributors were 

required to make reductions achievable by the application 

of highly cost effective controls. The court rejected this 

challenge finding that this result “flows ineluctably from 

EPA’s decision to draw the ‘significant contribution’ line 

on the basis of cost differentials.” Id.

Petitioners’ second objection to the use of uniform 

controls was that it failed to take into account the fact 

that the location of emissions reductions may affect the 

impact of those reductions on downwind nonattainment areas. 

Petitioners argued that because reductions closer to the 

nonattainment area have a greater benefit, EPA’s use of a 

highly-cost-effective standard and region-wide emissions 

trading did not guarantee that it would have secured the 

rule’s health benefits at the lowest cost. See 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
376

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 
377

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 
378

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 “Remedy 
379

Options Evaluated but not Proposed” describes options that 

EPA evaluated but is not proposing.

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 

SO2 and NOX emissions from EGUs through FIPs in the covered 

states to eliminate or address the states’ significant 

contribution to nonattainment in, or interference with 

maintenance by, downwind areas with respect to the daily 

and annual PM2.5 NAAQS and the 8-hour ozone NAAQS.

The remedy option EPA is proposing would use statespecific 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 
380

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 two 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 trading. The second alternative 

for which EPA requests comment is a direct control program 

in combination with state-specific control budgets.

As discussed in section IV.E, EPA is proposing new 

state 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 
381

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 
382

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 states81. 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 

 

81 The 32 states are: Alabama, Arkansas, Connecticut, 

District of Columbia, Delaware, Florida, Georgia, Illinois, 

Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, 

Massachusetts, Michigan, Minnesota, Mississippi, Missouri, 

Nebraska, New Jersey, New York, North Carolina, Ohio, 

Oklahoma, Pennsylvania, South Carolina, Tennessee, Texas, 

Virginia, West Virginia, and Wisconsin. As noted in 

section III, for purposes of this rulemaking, when we 

discuss “states” we are also including the District of 

Columbia.
383

these assurance provisions starting in 2014. 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 SO2 and/or NOX

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. 
384

To directly eliminate the portion of each state’s 

significant contribution and interference with maintenance

that EPA has identified in today’s action, the 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 
385

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 SO2, one 

for annual NOX, and one for ozone season NOX. One SO2

trading program is for sources in states (referred to as 

the SO2 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 SO2 group 2) with less stringent reduction 

requirements. States within SO2 group 1 can trade SO2

allowances only with other states in that group. 

Similarly, states within SO2 group 2 can trade SO2

allowances only with other states in that group. Note that 

all states covered for annual NOX may trade with each other, 

even if they are in different groups for SO2. Table IV.D.5

in section IV, previously, summarizes the respective 

covered states for the SO2 group 1, SO2 group 2, and annual 

NOX trading programs; Table IV.E-2 lists the states for the 

ozone season NOX program.

New emissions allowances based on the new state 

budgets without variability would be allocated to 
386

individual sources, as described later. Four sets of 

allowances would be allocated, one for each of the four 

trading programs (SO2 group 1, SO2 group 2, NOX annual, and 

NOX ozone season). This allocation methodology neither uses 

heat input adjusted by fuel factors, nor relies on the 

allocation of allowances under Title IV of the Act.

Sources would be allowed to trade 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. 
387

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, fossilfuel-fired combustion turbine serving at any time, since 

the later of November 15, 1990 or the start-up 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 
388

(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 a specified 

efficiency standard, i.e., the useful power plus one-half 

of useful thermal energy output of the unit must equal no 

less than a certain percentage of the total energy input 

or, in some cases, useful power must be no less than a 

certain percentage of total energy input. Total energy 

input includes all energy input except from biomass. 

These proposed elements of the “cogeneration unit” 

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 the efficiency standard every 
389

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 standard 

every year starting the later of November 15, 1990 or the 

start-up of the unit’s combustion chamber. EPA believes 

this definition of “cogeneration unit” is preferable 

because it may be problematic to obtain sufficiently 

detailed information about unit operations for some units 

(e.g., old units that may have started 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 back to November 15, 1990 

and whether the efficiency standard should be limited to 

even more recent years by requiring that the standard be 

met every year starting the later of a date (e.g., January 

1) of a more recent year (e.g., 2000 or 2005) or the startup of a unit’s combustion chamber. Second, in CAIR, each 

unit had to meet individually the efficiency standard. In 

contrast, under the “cogeneration unit” definition proposed 

here, if the cogeneration system of which a unit is a part 

meets the efficiency standard on a system-wide basis, then 
390

the unit is also deemed to meet that efficiency standard. 

EPA believes this definition is preferable because it 

addresses cases where one unit in a cogeneration system is 

operated at a lower efficiency (e.g., as a “swing” unit 

whose use varies with demand) to allow the rest of the 

units in the cogeneration system to operate with higher 

efficiency. 

If a unit meets the definition of cogeneration unit 

(including the efficiency standard), then it may qualify 

for the proposed cogeneration unit exemption depending on 

whether it meets additional criteria concerning the amount 

of electricity sales from the unit. In order to qualify 

for the exemption, a cogeneration unit would need to supply 

in any calendar year -– 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 
391

more recent years by requiring that the limit be met every 

year starting the later of a date (e.g., January 1) of a 

more recent year (e.g., 2000 or 2005) or the start-up of a 

unit’s combustion chamber. 

Solid waste incineration unit exemption. The proposed 

FIPs also includes an exemption for solid waste 

incineration units commencing operation before January 1, 

1985, for which the average annual fuel consumption of nonfossil 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 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 fossilfuel use limitation in the solid waste incineration unit 

exemption -- the term “fossil fuel” is limited to natural 
392

gas, petroleum, coal, or any form of fuel derived from such 

material “for the purpose of creating useful heat.” For 

example, this means that consumer products made from 

natural gas, petroleum, or coal are not fossil fuel, for 

purposes of determining qualification under the limitation 

on fossil-fuel use, because the products (e.g., tires) were 

derived from natural gas, petroleum, or coal in order to 

meet certain consumer needs (e.g., to meet transportation 

needs), not in order to create fuel (i.e., material that 

would be combusted to produce useful heat). 

Opt-in units. EPA does not propose to include 

provisions for units that are not otherwise covered to opt 

in to the trading programs in the proposed FIPs, or the 

alternative FIP options discussed later. For the Acid Rain 

Program, opt-in provisions were established by statute in 

section 410 of the Act. These opt-in provisions have been 

used, to date, by relatively few units. For CAIR, EPA 

promulgated opt-in provisions that became effective only to 

the extent that a state adopted the provisions in a SIP. 

While several states did adopt these opt-in provisions, no 

units so far have opted in to the CAIR trading programs. 

EPA believes, therefore, that it would not be useful to 

include opt-in provisions in the FIPs in the Transport 

Rule, and is not proposing any such provisions. 
393

Sources equal to or less than 25 MWe and Non-EGUs. 

Certain smaller EGUs and non-EGU sources that were included 

in the NOX Budget Trading Program were brought into the CAIR 

NOX ozone season trading program. For treatment of such 

sources in the proposed FIPs, see section V.F in this

preamble.

In the Northeast, a large number of EGUs serving 

generators with a nameplate capacity equal to or less than 

25 MWe contribute NOX emissions to ozone problems on high 

electric demand days. There is regional interest in 

lowering the 25 MWe applicability threshold in the ozone

season to deal with this issue and in potentially requiring 

these units to operate with greater controls than a trading 

program would necessitate. EPA requests comment on 

lowering the greater-than-25 MWe applicability threshold 

for EGUs during the ozone season, and whether a trading 

program offers the right approach for addressing NOX 

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 SO2, annual 

NOX, and ozone-season emissions budgets for that state 

identified in section IV.E (the state budgets listed in 

IV.E are the budgets without accounting for variability). 
394

As discussed later, EPA proposes to set aside 3 percent of 

each state’s emissions budgets for new units. Tables

IV.E.-1 and IV.E.-2 in section IV.E, referenced previously, 

show the permanent SO2, NOX, and ozone season NOX 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: SO2 group 1 allowances, SO2 group 2 allowances, 

NOX annual allowances, and NOX ozone season allowances.

In the SO2 group 1 and SO2 group 2 programs, each SO2

allowance would authorize the emission of one ton of SO2

annually. In the NOX annual program, each NOX annual 

allowance would authorize the emission of one ton of NOX

annually. In the NOX ozone season program, each NOX ozone 

season allowance would authorize the emission of one ton of 

NOX during the regulatory ozone season (May through 

September for this proposed rule). Note that, as explained 

in section IV.E, EPA is taking comment on extending the 

ozone season for this rule.

In each of the four trading programs, a covered source 

would be required to hold sufficient allowances to cover 

the emissions from all covered units at the source during 

the control period. EPA proposes to assess compliance with 
395

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 
396

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 

prior to January 1, 2009. 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 

(SO2 group 1, SO2 group 2, NOX annual, and NOX ozone season). 

This proposed allocation method is different from the 

allocation method used in the CAIR.
397

For states with lower SO2 budgets in 2014 (SO2 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 Rule cap and trade programs commence 

(see discussion of schedule, later). The allocations 

generally would be permanent (with the exception of nonoperating units, discussed later) as base amounts and would 

not be updated. (Note that any unused new source set aside 
398

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 SO2 group 1, SO2 group 2, NOX

annual, and NOX 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 unit82, or

if the unit stops operating for three consecutive years. 

 

82 If a unit was allocated allowances but turned out not to 

be a covered unit, then the treatment of the allocation 

depends on when the Administrator determines the unit is 

not subject to the trading program. For instance, if the 

allocation has been recorded, but the Administrator has not 

completed the compliance determination process for the 

unit, allowances equal to the allocation would be deducted 

from the unit’s compliance account.
399

Allocations to new units. EPA proposes to allocate 

emissions allowances to new units from new unit set-asides 

in each state. EPA proposes, for each of the four trading 

programs, to define a new unit as: any covered EGU not 

listed in the table in Appendix A of the trading rule 

applicable to that program; or any unit listed in Appendix 

A that stopped operating for three consecutive years, is no 

longer allocated allowances as an existing unit, but 

resumes operation.

EPA believes it is important to have a small new unit 

set-aside in each state to make room for new units that 

will be adding emissions to the state’s significant 

contribution and interference with maintenance. To create 

new unit set-asides, EPA 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 that will add to the 

state’s significant contribution to downwind nonattainment 

or interference with maintenance. 
400

For every control period after the control period in 

which a new unit commences commercial operation or, in the 

case of an existing unit that did not operate for three 

consecutive years, resumes operation, EPA would allocate to 

the unit from the new unit set-asides based on the unit’s 

reported emissions from the previous control period. EPA 

would not allocate to a new unit for the control period 

during which the unit commences commercial 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. 
401

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 SO2 group 1, SO2 group 2, NOX annual, and NOX

ozone season trading programs, as appropriate, for each 

state. EPA based the size of the proposed new unit setasides 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 would be allocated to the new unit set-aside for 

the state in which the retired unit is located. This 

approach would allow the size of the new unit set-asides to 
402

grow over time. Note that in EPA’s analysis to determine 

the size of the new unit set-asides, EPA assumed that 

allocations for non-operating units would be allocated to 

the new unit set-asides after a unit had ceased operating 

for 3 consecutive years (see “State Budgets, Unit 

Allocations, and Unit Emissions Rates” TSD). EPA requests 

comment on the size of the new unit set-asides.

Non-operating units. EPA proposes that, once an EGU 

does not operate (i.e., does not combust any fuel) for 3 

consecutive years, the Agency would no longer allocate 

allowances to the unit. Starting with the seventh year 

after the first year during which unit is not operating, 

all allowances that would otherwise have been allocated to 

the unit for that seventh 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).
403

EPA proposes to continue allocating allowances to nonoperating units during 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 

immediately discontinuing allocations to such units upon 

the unit ceasing operation.

Continuing allocations to non-operating 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 setaside 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 
404

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 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 

June 1, 2012 for control periods in 2015. Recording 

allowances several years in advance supports the 
405

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. 
406

EPA proposes to record allowances for new units by 

September 1, 2012 and September 1 of each year thereafter, 

for the control periods in the year that the allowances are 

recorded. (For the units in the NOX 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 two 

alternative allocation methods. EPA is requesting comment 

on whether either alternative should be used instead of the 

proposed allocation method. 

As discussed in section IV, the state emissions 

budgets are determined based on EPA’s analysis of 

significant contribution and interference with maintenance 
407

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 two alternative methodologies 

that still link unit allowances directly to the way state 

budgets were developed (and thus, significant contribution 

was defined). In the alternatives, allowances are equally 

distributed amongst groups of units such that for each 

group of units, the amount of allowances distributed is 

equivalent to the way that significant contribution was 

apportioned for the group of units.

In the first alternative, all units within a state

would be treated as a single group. The 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 
408

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. 

In the second alternative allocation method, EPA would 

identify groups of units in each state that are capable of 

having similar emissions characteristics (e.g., coal units, 

oil units, natural gas units). EPA would distribute a 

state’s emissions budget without variability to each group 

of units in the state (in effect, distributing the 

responsibility for eliminating all or part of significant 

contribution) based on each group’s proportional share of 

the budget as projected in the initial year of the program. 

After apportioning a state’s budget to the groups of units, 

EPA would distribute allocations to individual sources 

within each group based on each source’s proportional share 

of projected heat input. Like the first alternative 

allocation method described previously, this alternative 

distributes each state’s significant contribution and 
409

interference with maintenance to individual sources in the 

state. By determining groups and then distributing 

allocations within the groups based on proportional shares, 

this method would treat units within the categories equally 

(i.e., the method would not penalize a source that had 

acted early to control). 

(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 SO2 programs and 

the NOX programs would remain separate trading programs 

maintained in EPA’s existing AMS. AMS would be used to 

track Transport Rule trading program SO2 and NOX allowances 

held by covered sources, as well as such allowances held by 

other entities or individuals. Specifically, AMS would 

track the allocation of all SO2 and NOX allowances, holdings 

of SO2 and NOX allowances in compliance accounts (i.e., 

accounts for individual covered sources) and general 

accounts (i.e., accounts for other entities such as 

companies and brokers), deduction of SO2 and NOX allowances 

for compliance purposes, and transfers of allowances 
410

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 SO2 and NOX emissions in 

accordance with 40 CFR part 75. Sources that would be 

covered by the proposed Transport Rule are already 

measuring and reporting SO2 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 NOX 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 
411

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 SO2 and NOX

emissions by all existing covered sources by January 1, 

2012 for states covered for the daily and/or annual PM2.5

NAAQS, and monitoring of NOX 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 
412

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. 

(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 
413

country’s electric demand will be met while meeting the 

statutory requirement of eliminating significant 

contribution. 

Starting in 2014, EPA is proposing as part of the FIPs 

to establish limits on the total emissions that may be 

emitted from EGUs at sources in each state. For any single 

year, the state’s emissions must not exceed the state 

budget with the variability limit allowed for any single 

year for 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-
414

year variability limit in any one year, and the state’s 

annual average emissions for any 3-year period can not 

exceed, on average, the state budget with the state’s 3-

year variability limit. The fact of the 3-year variability 

limit would further assure that emissions are constrained 

during the two preceding years.

For example, a hypothetical state has a budget of 

100,000 tons, a 1-year variability limit of 10,000 tons, 

and a 3-year variability limit of 5,800 tons.

 In the first year, collective emissions from covered 

EGUs in the state are 120,000 tons, 10,000 tons over 

the budget with 1-year variability limit of 110,000 

tons, triggering the assurance provisions in 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 
415

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 
416

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 units’ allocations plus the owner’s 

share of the state budget with the variability limit would 

be subject to the allowance surrender requirement.

In applying the additional criteria, EPA would 

evaluate which source owners in the state had emissions 

exceeding the respective owner’s share of the state budget 

with the variability limit (regardless if the source had 

enough allowances to cover its emissions). An owner’s 

share would equal the sum of the allocations of its EGUs in 

the state, plus its proportional share of the amount of the 

variability limit that, when included with the state 

budget, was exceeded by the state’s EGU emissions during 
417

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 

state budget with the variability limit –- would 
418

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 coalfired units, 66 percent for gas-fired combined cycle units, 

and 15 percent for combustion turbines in the NOX annual and 

SO2 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 NOX 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 coalfired 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 
419

thus avoid attributing to each new unit a share of the 

state budget with variability equal to the maximum amount 

of emissions possible for the unit in its first operating 

year, in the 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). 

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 today’s proposed action; and 

additional allowance surrender requirements for not meeting 

emissions reductions requirements. As discussed in section 

e, later, the underlying mechanism of cap and trade, even 
420

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 NOX 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 
421

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 
422

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 SO2 or NOx emitted and are subject to penalties if 

they fail to comply with this allowance-holding 

requirement.
423

Each source must hold in its compliance account in the 

AMS enough allowances issued for the respective annual 

trading program (SO2 group 1, SO2 group 2, or NOx annual 

programs) to cover the annual emissions of the relevant 

pollutant from all the EGUs at the source. The source 

owner must provide, for deduction by the Administrator, one 

allowance as an offset and one allowance as an excess 

emissions penalty for each ton of excess emissions. These 

are automatic penalties –- they are required, without any 

further action by EPA (e.g., any additional proceedings), 

regardless of the reason for the occurrence of the 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
424

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 201483. 

 

83 U.S. Environmental Protection Agency (U.S. EPA). 2002. 

Engineering and Economic Factors Affecting the Installation 

of Control Technologies for Multipollutant Strategies. 

Washington, D.C.
425

Consequently, EPA believes that there is a high level 

of certainty that emissions reductions projected for 2012-

2013 with interstate trading would be achieved within the 

states where they are projected to occur, making imposition 

of the assurance provisions during 2012-2013 unnecessary. 

In addition, EPA 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 SO2 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 
426

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.F4).

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 NOx SIP Call, and CAIR
427

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 SO2 emissions cap and trade 

program that EPA implemented under Title IV of the CAA 

Amendments (the Acid Rain Program) and the regional SO2 and 

NOX programs established under CAA section 110(a)(2)(D)(i), 

in the form of the NOX Budget Trading Program and the three 

CAIR trading programs, all have several key components in 

common:

 Phases and reductions

o An emissions cap is established and the programs 

are phased in, with increasing stringency to 

lower emissions.

 Allowance allocation

o Authorizations to emit, i.e., allowances, are 

allocated to affected sources and are limited by 

each state’s trading budget. 

 Allowance trading

o Markets enable sources to trade allowances. 

 Flexible compliance

o Sources have the flexibility to choose the most 

efficient way to comply including adding emission 
428

control technologies, updating control 

technologies, optimizing existing controls, 

switching fuels, and buying allowances.

 Annual reconciliation 

o At the end of every compliance period, each 

source must surrender sufficient allowances to 

cover its emissions. Excess allowances may be 

sold or banked for future use.

 Penalties and enforcement

o There are automatic penalties and potentially 

discretionary civil penalties for program 

noncompliance.

 Stringent monitoring and reporting

o Sources must use approved monitoring methods 

under EPA’s stringent monitoring requirements (40 

CFR part 75) to monitor and report emissions.

 Data transparency

o The data on key program elements, such as 

emissions, allocations, and allowance trades, are 

publicly available on EPA’s web site and in 

annual progress reports. 

About 50 government staff operate these cap and trade 

programs. They have been successful in achieving the 

emissions reductions goals at reasonable costs with 
429

virtually 100 percent program compliance. In the following 

paragraphs, specific results from the programs are 

described. These results are documented in program 

progress reports that are available on EPA’s web site 

(www.epa.gov/airmarkets/progress/progress-reports.html) and 

in the docket to this rule, as referenced at the end of 

each program section later.

Title IV Acid Rain Program -- Emissions Reductions. 

Since program implementation in 1995, the ARP has reduced 

SO2 and NOx emissions from the power sector across the 

nation. In 2008, the ARP SO2 program covered 3,572 electric 

generating units (including 1,055 coal-fired units, which 

account for almost 99 percent of total ARP unit SO2 

emissions). Verified data submitted to EPA from 2008 show 

that: 

 SO2 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. 

 NOx 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 NOx program 

emission reduction objective, but also reflects 
430

reductions achieved under the NOX Budget and CAIR NOX

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. PM2.5 and ozone 

health-related benefits estimate that PM2.5 benefits 

due to ARP implementation in 2010 are valued at $170-

410 billion annually and ground-level ozone benefits 

from ARP implementation in 2010 are valued at $4.1-$17 

billion (estimates are in 2008 dollars). The benefits 

are primarily from reduced premature mortality.
431

See EPA’s docket for this rule and 

www.epa.gov/airmarkets/progress/ARP_4.html.

NOX SIP Call NOX Budget Trading Program -- Emissions 

Reductions. From 2003-2008, the NBP reduced ozone season 

NOx emissions throughout the NOX SIP call region each year. 

Results of the program include: 

 In 2008, NBP ozone season NOx emissions totaled 481,420 

tons, which is 62 percent below 2000 levels and 9 

percent below the 2008 NOX emissions cap. Emissions 

were also below the caps in 2006 and 2007.

 The average NOx emission rate for the 10 highest 

electric demand days (as measured by megawatt hours of 

generation) consistently fell every year of the NBP. 

 The largest NOx 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 NOx 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 
432

in 2008. 8-hour ozone concentrations were 10 percent 

lower in 2008 than in 2001. This decline is largely 

due to reductions in NOX emissions required by the NOX

SIP call rule.84 

Over the past several years a series of studies85,86,87

have evaluated the NOx SIP call and the link between 

decreasing NOx emissions and decreasing ozone 

concentrations. These studies demonstrate that the NOx 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 

 

84 US EPA, Our Nation’s Air Status and Trends through 2008, 

Office of Air Quality Planning and Standards, EPA-454/R-09-

002, Research Triangle Park, NC, pp. 1, 17.

85 Gégo, E., P.S. Porter, A. Gilliland, and S.T. Rao, 2007: 

Observation-Based Assessment of the Impact of Nitrogen 

Oxides Emissions Reductions on Ozone Air Quality over the 

Eastern United States. J. Appl. Meteor. Climatol., 46, 994–

1008.

86 Godowitch, J.M., Hogfrefe, C., & Rao, S.T. 2008. 

Diagnostic analyses of a regional air quality model: 

Changes in modeled processes affecting ozone and chemicaltransport indicators from NOX point source emission 

reductions. Journal of Geophysical Research, 113, D19303, 

doi:10.1029/2007JD009537. 

87 Godowitch, J.M., Gilliland, A.B., Draxler, R.R., and Rao, 

S.T. 2008. Modeling assessment of point source NOx emission 

reductions on ozone air quality in the eastern United 

States. Atmospheric Environment, 42 (1) 87–100.
433

reductions requirements under the NOX SIP Call and can use 

the CAIR NOx ozone season trading program to meet these. 

See EPA’s docket for this rule for more details on the 

results of the NOx Budget Trading Program, or see 

www.epa.gov/airmarkets/progress/NBP_4.html.

CAIR -- Emissions Reductions. Anticipation of the 

CAIR regional program in 2008 resulted in an additional 2.8 

million tons of SO2 reductions from 2005 levels in the 

eastern United States, bringing emissions well under the 

2010 Title IV cap. The NOX annual and ozone season programs 

began on January 1 and May 1, 2009, respectively. The SO2

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 
434

allowance markets remained active. For a recent assessment 

on allowance markets, see

www.epa.gov/airmarkets/resource/docs/marketassessmnt.pdf.

Transaction Costs. The cap and trade program results 

described previously are real, measurable, and very 

significant. These results demonstrate that cap and trade 

is a policy tool that can achieve cost-effective, broad 

reductions quickly to improve human health and the 

environment and help states meet their obligations to 

attain the NAAQS. While 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 SO2 cap and trade 

program by Ellerman88 of MIT, published in 2004. Ellerman 

suggests that, while no comprehensive study has been 

conducted on the subject, “. . .the creation of a standard 

 

88 Ellerman, A. Denny. 2004. "The U.S. SO2 Cap-and-Trade 

Programme," Tradeable Permits: Policy Evaluation, Design 

and Reform, chapter 3, pp. 71-97, OECD. 
435

unit of account in allowances and the lack of any review 

requirement for trading has avoided the very large 

transactions costs that limited . . . earlier experiments 

with emissions trading.” Other studies (see Schennach, 

200089) suggest transaction costs are about one percent of 

the allowance price. An industry expert, Gary Hart90, 

suggested that a typical fee charged by a brokerage firm is 

$0.50 for each SO2 allowance.

Tietenberg, in his book, Emissions Trading Principles 

and Practice91, 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 

 

89 Schennach, S.M. 2000. The Economics of Pollution Permit 

Banking in the Context of Title IV of the 1990 Clean Air 

Act Amendments. Journal of Environmental Economics and 

Management 40(3): 189-210.

90 Personal communication with Gary Hart, ICAP-United, June 

25, 2007 as quoted in Napolitano, S., J. Schreifels, G. 

Stevens, M. Witt, M. LaCount, R. Forte, & K. Smith. 2007. 

“The U.S. Acid Rain Program: Key Insights from the Design, 

Operation, and Assessment of a Cap-and-Trade Program.”

Electricity Journal. Aug./Sept. 2007, Vol. 20, Issue 7.

doi:10.1016/j.tej.2007.07.001.

91 Tietenberg, T.H. 2006. Emissions Trading Principles and 

Practice. Washington, D.C. Published by Resources for the 

Future.
436

the market, finding buyers or sellers, negotiating and 

enforcing contracts for permit transfers, completing all 

the regulatory paperwork, and making and collecting 

payments.”92 He also describes how to lower transaction 

costs, as follows: “Transaction costs can be lowered by 

making permit transactions transparent, by the availability 

of exchanges and knowledgeable brokers, and by the sharing 

of information on the availability of cost-effective 

abatement technologies, while administrative costs can be 

lowered by continuous emissions monitoring and by software 

that streamlines monitoring and reporting.”93 He goes on to 

say, “Price transparency (making prices public) can reduce 

the uncertainty associate with trading and facilitate 

negotiations about price and quantity. One good example is 

[the]...public auctions held each spring for the Sulfur 

Allowance Program [ARP].”94

Tietenberg contrasts EPA’s earlier credit-based 

trading programs in the 1970s and 1980s (U.S. Emissions 

Trading Program (ETP)) with cap and trade programs, such as 

the Acid Rain Program for SO2. He says that while creditbased programs “typically involved a considerable amount of 

 

92 Ibid., p. 41

93 Ibid., p. 73

94 Ibid. pp.70-71
437

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-of-the-art information management system has evolved 

in parallel with the advancement of technology in order to 

offer platforms for reporting and receiving data and for 

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 
438

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, NOX 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 
439

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.95 In 

many instances, clients can negotiate fees even lower than 

market averages. Financial exchanges, such as the Chicago 

 

95 Memo from ICF International to EPA Clean Air Markets 

Division, September 17, 2008. Transaction Costs in 

Allowance Trading Markets.
440

Climate Exchange and New York Mercantile Exchange, added SO2

and NOX allowances to their list of commodities. Prior to 

the vacatur of CAIR, transaction costs (broker fee as a 

percent of allowance price) were estimated at less than 0.2 

percent for SO2, less than 1.8 percent for seasonal NOX, and

less than 0.5 percent for annual NOX.

96 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 SO2 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 

 

96 Ibid.
441

concern about the costs of making allowance transfers. For 

example, EPA has received no comment in the rulemaking 

proceedings for the trading programs raising concern about 

the level 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 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 
442

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 eliminated97. State budgets 

represent EPA’s estimate of the remaining emissions after 

elimination of significant contribution, but in actuality 

the amount of remaining emissions may vary. As explained 

in greater detail previously, both the budgets and the 

assurance provisions recognize the inherent variability in 

state EGU emissions. EPA recognizes that shifts in 

generation due to changing weather patterns, demand growth, 

or disruptions in electricity supply from other units, all 

can affect the amount of generation needed in a specific 

state and thus baseline EGU emissions from that state. 

Because states’ baseline emissions are variable, their 

remaining emissions after all significant contribution is 

eliminated are also variable. In other words, EGU 

emissions in a state, whose sources have installed all 

 

97 Note that in cases where EPA has not fully identified the 

quantity of 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.
443

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 
444

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-fuelbased electric generation, the impact of an outage of nonfossil-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 
445

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. 
446

In the first phase (2012 and 2013), the proposed 

remedy would provide a new interstate trading program that 

would ensure existing and planned pollution controls 

operate. Units would be required to run their existing, or 

already planned, 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, 
447

and EPA to implement a transition from CAIR. While there 

is some uncertainty about how quickly units potentially 

capable of switching fuels would actually be able to 

implement such 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 SO2 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 
448

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), 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., 
449

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 unitspecific 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 
450

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 NOX 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 
451

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 But 

Not Proposed

EPA considered a range of ways to create an 

interstate-trading-with-limitations option consistent with 

the direction provided by the Court. One option considered 
452

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. EPA is not proposing this approach because data on 

annual emissions are not final until several months into 

the next year, making it hard for the units in a state to 

know early enough whether they would be in the interstate 

trading program or an intrastate trading program for that 

next year. This would make compliance planning and 

implementation of compliance plans extremely difficult and 

adversely affect allowance markets. 

In summary, EPA rejected these alternatives as more 

complicated and perhaps problematic to implement. Instead, 

EPA is proposing the State Budgets/Limited Trading remedy, 
453

which is similar in many ways to the approaches implemented 

in the past that have succeeded in reducing emissions. 

However, in order to address the Court’s concerns about 

trading, the proposed remedy includes assurance provisions 

to ensure that the remedy removes each upwind state’s 

significant contribution and interference with maintenance. 

The “Remedy Options Evaluated but Not Proposed” TSD in the 

docket contains greater detail on the deliberations 

undertaken to evaluate other options, not proposed, for 

this rulemaking.

i. Structure and Key Elements of Proposed Transport Rule

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 

explicitly requests comment on the structure and key 

elements of the program as well as on the proposed 

regulatory text.

In order to make the proposed FIP trading program 

rules as simple and consistent as possible, EPA designed 

them so that the proposed rules for each of the trading 
454

programs (i.e., the Transport Rule NOX Annual trading 

program, Transport Rule NOX Ozone Season trading program, 

Transport Rule SO2 Group 1 trading program, and Transport 

Rule SO2 Group 2 trading program) would be parallel in 

structure and contain the same basic elements. For 

example, the proposed rules for the Transport Rule NOX

Annual, NOX Ozone Season, SO2 Group 1, and SO2 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 (NOX and SO2), control periods (for 

NOX, annual and ozone season), and geographic coverage (for 

SO2, Group 1 and Group 2) involved. Moreover, many of the 

definitions would be essentially the same as those used in 
455

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 NOX Annual 

allowances, Transport Rule NOX Ozone Season allowances, 

Transport Rule SO2 Group 1 allowances, or Transport Rule SO2

Group 2 allowances or Transport Rule NOX Annual units and 

sources, Transport Rule NOX Ozone Season units and source, 

Transport Rule SO2 Group 1 units and sources, or Transport 

Rule SO2 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.
456

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 
457

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 

allowance-holding requirements. However, an owner would 

include each of these permanently retired units that it 

owns in determining whether and, if so, how many allowances 
458

the owner would be required to surrender in compliance with 

the assurance provisions. As discussed earlier in this 

section, while these units would have zero emissions once 

they are permanently retired, the units could continue to 

receive allowance allocations for several years thereafter. 

Consequently, an owner would include these units would be 

included in determining whether the owner’s share of total 

emissions of covered units in a state exceeded its share 

(generally based on the allowances allocated to its units) 

of the state budget with the variability limit and thus 

whether the 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 provisions would not 

directly address any permit-related 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 
459

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 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 
460

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 NOX Annual allowances, Transport Rule 

NOX Ozone Season allowances, Transport Rule SO2 Group 1 

allowances, or Transport Rule SO2 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 Clean Air Act; and such 

allowances would not constitute a property right. The 

proposed Transport Rule SO2 trading programs use new SO2

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 SO2 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 
461

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 
462

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-time provisions used in prior 

EPA-administered 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 
463

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 types of 

administrative proceedings), would also be moved to § 78.2. 

In particular, the revised “interested person” definition 

would include, with regard to a decision appealable under 

part 78, would include, with regard to a decision 

appealable 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 
464

Administrator under the proposed Transport Rule trading 

programs. Further, § 75.4 would be expanded to state that 

filings on behalf of owners and operators of a covered 

source or unit under the proposed Transport Rule trading 

programs would have to be signed by the designated 

representative of the source or unit. Filings on behalf of 

persons with an interest in allowances in an account in the 

proposed programs would have to be signed by the authorized 

account representative of the account.

(2) Allowance Allocations 

Sections 97.410 through 97.412, 97.510 through 97.512, 

97.610 through 97.612, and 97.710 through 97.712 would set 

forth: certain information related to allowance allocation 

and for implementation of the assurance provisions; the 

timing for allocation of allowances to existing and new 

units; and the procedures for new unit allocations. In 

particular, these sections would 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 
465

program rules. These allocations would be permanent 

(taking into account the reductions in allocations, for the 

Transport Rule SO2 Group 1 trading program, from phase 1 to 

phase 2) with one exception. A unit that does not operate 

(i.e., has no heat input) for three consecutive years 

starting in 2012 would continue to receive its 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, 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 unit-by-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 (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 
466

allocation from the new unit set-aside for that year and 

each year thereafter. The allocation would equal that 

unit’s emissions –- as determined in accordance with Part 

75 (40 CFR part 75) –- of the control period (annual or 

ozone season, depending on the Transport Rule trading 

program involved) in the preceding year. The Administrator 

would determine whether the total number of properly 

requested allowance allocations for all units in a state 

for a control period would exceed the amount in the new 

unit set-aside for the state for the control period. If 

not, the Administrator would allocate consistent with all 

proper requests. If the total number would exceed the new 

unit set-aside, the Administrator would allocate to each 

properly requesting unit its proportionate share of the new 

unit set-aside. The Administrator would provide notice of 

these determinations (which would reflect these 

calculations rather than any exercise of discretion on the 

part of the Administrator) through issuance of a notice of 

data availability to which parties could submit objections 

and second notice addressing any objections. Any 

unallocated allowances in the new unit set-aside would be 

allocated to existing units in proportion to their current 

allocations. 
467

If a unit that was not really a covered unit were 

erroneously allocated allowances, the proposed provisions 

set forth a process under which the allocation would not be 

recorded or the recorded allocation would be deducted, with 

one exception. The exception would be if the process of 

determining compliance with the emission limitation for the 

source that includes the unit were already completed, in 

which case no action would be taken to account for the 

erroneous allocation for the control period involved.

(3) Designated 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 
468

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 program. One alternate 

designated representative could be selected to act on 

behalf of, and legally bind, the designated representative 

and thus the owners and operators. Because the actions of 

the designated representative and alternate would legally 

bind the owners and operators, the designated 

representative and alternate would have to submit a 

certificate of representation certifying that each was 

selected by an agreement binding on all such owners and 

operators and was authorized to act on their behalf. 

The 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 
469

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 
470

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 
471

approach in prior EPA-administered trading program, 

allowance price information would not be included in the 

Allowance Management System. EPA’s experience is that 

private parties (e.g., brokers) are in a better position to 

obtain and disseminate timely, accurate allowance price 

information than is EPA. For example, because not all 

allowance transfers are immediately reported to the 

Administrator for recordation, the Administrator would not 

be able to ensure that any reported price information 

associated with the transfers would reflect current market 

prices.

(vi) §§ 97.420, 97.520, 97.620, and 97.720 –- Compliance 

and General Accounts 

The Allowance Management System would contain two 

types of accounts: 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 
472

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 sourcelevel 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 
473

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 
474

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 NOX and SO2 annual trading programs and June 

1, for the Transport Rule NOX Ozone Season program) of each 

year starting with 2012, the Administrator would record 

allowance allocations for that year from the new unit setaside. 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 
475

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 NOX and SO2 annual trading programs and 

September 30 for the NOX 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 
476

source’s total emissions for the control period. The 

authorized account representative could identify specific 

allowances to be deducted, but, in the absence of such 

identification or in the case of a partial identification, 

the Administrator would deduct on a first-in, first-out 

basis.

If a source were to fail to hold sufficient allowances 

for compliance, then the owners and operators would have to 

provide, for deduction by the Administrator, 2 allowances 

allocated for the 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 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 
477

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 units’ allocations plus 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, 
478

and whether those owners were in compliance would be 

implemented in a series of steps. (The dates summarized 

later apply to the proposed annual programs; the dates for 

the proposed ozone season 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 
479

entitlement in the Transport Rule units at the source; and 

the amount of each such person’s reservation or 

entitlement. 

Third, by September 15, the Administrator would 

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 
480

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 
481

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 
482

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. Owners’ potential allowance 

surrender obligations as of the December 15 allowanceholding 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 
483

-- 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 
484

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 
485

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 NOX annual, NOX ozone 

season, SO2 Group 1, and SO2 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 NOX

and SO2 mass emissions are found. The proposed provisions 

are virtually the same as the monitoring, recordkeeping, 

and reporting requirements under previous EPA-administered 

trading programs, e.g., the ARP and NOX Budget and CAIR 

trading programs. 
486

 Part 75 was originally developed for the ARP and 

addressed SO2 mass emissions and NOX emission rate. The 

ARP, as established by Congress in CAA Title IV, requires 

the use of continuous emission monitoring systems (CEMS) or 

an alternative monitoring system that is demonstrated to 

provide information with the same precision, reliability, 

accuracy, and timeliness as a CEMS. Subsequently, Part 75 

was expanded, for purposes of the NOX Budget Trading Program 

under the NOX SIP Call, to address monitoring and reporting 

of NOX mass emissions. Under Part 75, a unit has several 

options for monitoring and reporting, namely the use of: a 

CEMS; an excepted monitoring methodology (NOX mass 

monitoring for certain peaking units and SO2 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 
487

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 NOX and/or SO2

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 properly, standard 

substitute data procedures are applied and result in a 

conservative estimate of emissions for the period involved. 
488

This ensures a level playing field among the regulated 

units, with consistent accounting for every ton of

emissions, and also provides an incentive to properly 

maintain, and meet the QA requirements for, each monitoring 

system. The monitoring and reporting provisions in the 

proposed Transport Rule trading program regulations would 

contain the same QA requirements and substitute data 

procedures as in Part 75 and would reference the applicable 

provisions in Part 75. 

Part 75 requires electronic submission, to the 

Administrator and in a format prescribed by the 

Administrator, of a quarterly emissions report 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 
489

contain the same requirements for submission to the 

Administrator of electronic, comprehensive quarterly 

reports as in Part 75. 

5. State Budgets/Intrastate Trading Remedy Option 

As noted earlier in this preamble, in addition to the 

remedy option included in the proposed FIPs, EPA is taking 

comment on two alternative options for 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 SO2, NOX annual, and NOX ozone 

season emissions from EGUs and create separate allowance 

trading programs within each state in the respective 

regions starting in 2012. The state-specific caps would
490

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. 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 the allowance 

holders would only be allowed to trade exclusively with 

others within the same state. Even a company that operates

EGUs in multiple states would not be permitted to trade or 

transfer allowances to its other facilities or accounts 

other than those within the same state. In essence, this 

approach, if implemented, would result in 28 separate 
491

trading programs for NOX annual, 26 trading programs for NOX

ozone season, and 28 trading programs for SO2 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 emissions 

variability. EPA also requests comment on whether 
492

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. 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 and Market Concentration Technical 

Support Document). To address this potential weakness in 
493

the allowance markets in numerous states through 

allocations, 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 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 may 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 allowance 

markets and put small owners of fossil-fuel fired 

generation at a disadvantage regarding their compliance 

costs unless the owners were given sufficient access to 

allowances other than through direct purchase from the 

state’s dominant companies. Some of these owners of a 

small share of generation may already face higher control 

costs, higher transaction costs, and less flexibility 

regarding compliance options. 

Moreover, the use of allowance market power to 

manipulate prices could have wider impacts on electricity 

markets as a whole, electricity prices, and electricity 
494

reliability both within and across state borders. 

Therefore, the State Budgets/Intrastate Trading approach 

needs to address the potential for excessive market power 

and ensure that allowances will be available to all covered 

sources at reasonable market prices.

In order to address the potential market power issue, 

under this option, not all allowances would 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 non-operating units above for State 
495

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 SO2 and NOX ozone season and NOX 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. section 3302.

EPA would use auctions to address market power 

concerns rather than other options it considered. The 

Agency considered using a different allowance allocation 
496

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 several years of experience 
497

running single-round, sealed-bid auctions for SO2. Other 

formats considered such as multi-round auctions are 

believed to be more complicated for participants to 

understand, more complex to administer and do not 

discourage collusion. Further, it is not assured that 

another format would maximize revenue compared to EPA’s 

suggested format. 

Entities that meet the following criteria would be 

eligible to participate in the allowance auction: (1) they 

are required to hold allowances in the state for 

compliance; and (2) they own no more than 10 percent of the 

total fossil-fuel fired generation within the state based 

on EPA’s modeled generation for 2014. EPA considered a 

range from 5 to 20 percent share of ownership for all 

states and believes that 10 percent ownership is 

appropriate for determining what constitutes a small market 

share for this rule. EPA believes that by limiting the 

auction to entities 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 
498

units, have more flexibility, receive a significant share 

of allowances, and face lower control and transaction 

costs. EPA is explicitly requesting comment on the share 

of electric generation used as a threshold for determining 

participation in auctions and also the percentage of 

allowances available through auctions.

To implement this option, EPA would withhold 2 to 5

percent of the allowances that would be allocated to 

companies with more than 10 percent of the generation in 

order to supply allowances for auction each period. This 

amount is small enough not to have a significant impact on 

those EGUs from which the allowances are withheld and large 

enough to provide a sufficient number of allowances for 

auction. In more highly concentrated states where few 

companies control much of the generation, a relatively 

greater number of allowances would be available through the 

auction to the smaller, potentially disadvantaged 

companies. Conversely, in states where the electricity 

sector is less concentrated, there is less threat of market 

manipulation and greater likelihood of liquid markets.

Thus, in these states relatively fewer allowances would be 

withheld for auction.

Another variation on this alternative approach would 

be to divide companies in each state into three groups, 
499

instead of just two. The first group would be the 

companies that own no more than 10 percent of the total 

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 

fossil-fuel fired generation (for example, between 10 to 20

percent of the total). These companies would not be 

allowed to participate in auctions but also would not have 

to contribute any allowances to the auctions. Finally, the 

third group would be those remaining companies that own a 

large share of fossil-fuel generation (for example, more 

than 20 percent of the total). A small percentage of the 

allowances allocated to these companies would be withheld 

to supply the auctions. EPA is asking for comments on this 

alternative and other ways to address potential market 

power problems and on this alternative approach. 

(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.
500

(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 SO2 or 28 NOX

annual programs), the requirement that each source hold in 

its compliance account one allowance for each ton of 

emissions, and the penalties for failure to meet this 

requirement, would be the same as described previously in 

the Penalties section for the State Budgets/Limited 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 
501

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 emission reductions occur 

“within the State.” 

To implement this remedy option, EPA would use the

state budgets without variability limits, developed in 

accordance with the procedures described in sections IV.D 

and IV.E. These budgets represent EPA’s projection of each 
502

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 
503

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
504

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.

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 
505

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 NOX 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 NOX 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 NOX. 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 NOX

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 NOX

emissions at a level modeled as necessary for the area to 

reach ozone attainment. The MECT program started January 

1, 2002 and the NOX cap stepped down each subsequent year 
506

until reaching the final cap level of 80 percent of the 

baseline NOX emissions in January 2007. In the MECT program 

one allowance is equivalent to one ton of NOX 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 NOX 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 
507

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 NOX and SO2

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 
508

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 NOX 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 NOX rose from 

about $3,000 per ton early in 2000 to nearly $20,000 per 

ton in June and up to about $70,000 per ton in August of 

that year. Prices of RTCs during the California energy 

crisis during 2000 and 2001 averaged in the $50,000 per ton 

range.

98

 While the California crisis was the result of 

several malfunctions in the market, the RTC price spike was 

exacerbated by a number of factors starting with the fact 

that few emissions reductions had been made in earlier 

years. Prior to the California crisis, RTCs had been 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 

 

98 Joskow, Paul and Edward Kahn, 2002. A Quantitative 

Analysis of Pricing Behavior In California’s Wholesale 

Electricity Market During Summer 2000: The Final Word.
509

were partly caused by the high demand for credits resulting 

directly from the manipulation of the power market by 

generators.

99

The operation of the RECLAIM market also contributed 

to the high prices in the overall power markets. During 

this period, generators would pay 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.

100

 Since that time, 

significant changes have been adopted to improve the 

program.

 

99 Kolstad, Jonathan T. and Frank A. Wolak, 2003. Using 

Environmental Emissions Permit Prices to Raise Electricity 

Prices: Evidence from the California Electricity Market. 

Published by University of California Energy Institute.

100 Holland, Stephen P. and Michael Moore, 2008. When to 

Pollute, When to Abate? Intertemporal Permit Use in the Los 

Angeles NOX Market. Published by University of California 

Energy Institute.
510

According to the audit report for the 2007 compliance 

period, total aggregate NOX emissions were below total 

allocations by 21 percent and total aggregate SOX emissions 

were below total allocations by 13 percent. Since January 

2008, NOX RTCs prices have been declining and have not 

exceeded $15,000 per ton.

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 
511

since sources would have less flexibility and fewer options 

for compliance. EPA is requesting comments on this 

approach, specifically on alterations that could address 

the drawbacks identified above or on any other weaknesses 

of this option not identified by EPA. EPA also welcomes 

comments regarding the validity of the concerns with this 

approach identified above.

6. Direct Control Remedy Option

The second alternative option EPA is requesting 

comment on is the direct control option described later. 

EPA is considering the relative merits of this option and 

requests comment on whether a direct 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 

emission rate limits to individual sources. Emissions 

limits would take the form of input-based emissions rate 

limits (lb/mmBtu).

EPA explicitly requests comments on the direct control 

remedy summarized later and the approach for determining 

emission rate limits, which is described in greater detail 

in the “State Budgets, Unit Allocations, and Unit Emissions 

Rates” TSD in the docket for this rulemaking. 
512

Specifically, EPA requests comment on the general use of a 

direct control remedy as well as the specific rate-based 

direct control approach described later. EPA also requests 

comment on the potential weakness of this remedy option 

identified in the discussion later. In addition, EPA 

requests comment on alternate methodologies which could be 

used to implement a direct control remedy.

See section V.E. later for projected costs and 

emissions associated with this option.

a. Description of Option

Unlike the proposed remedy option (State 

Budgets/Limited Trading) and the other alternative remedy 

option (Intrastate Trading) discussed previously, which 

both use flexible cap-and-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 emission 

rate limits covering all of its EGUs in each covered state. 

In a state covered for the 24-hour and/or annual PM2.5

NAAQS, the direct control remedy option would require each 

company within the state to meet specified EGU annual 

emission rate limits for SO2 and NOX. In a state covered 

for the 8-hour ozone NAAQS, this remedy would require each 

company within the state to meet specified EGU ozone season 
513

emission rate limits for NOX. EPA would set emission rates 

on a unit-by-unit basis in all covered states (see approach 

to determine emission rate limits, later).

While emission rates in all states would be set on a 

unit-by-unit level, a company would be allowed to average 

the emissions at its units within each state to meet the 

specified within-the-state rate limits. Company-level 

average rates would be calculated as company-level total 

emissions divided by company-level total heat input in each 

state. Analogously, allowable company-level average rates 

would be calculated using unit-specific rate limits and the 

heat inputs used to determine those allowable rates (as 

discussed in 6.b.1). A company that exceeded the 

applicable average rate limits would be subject to 

penalties (described later).

In addition, to address the potential variability in 

annual emissions associated with emission rate limits

(i.e., not all years are average), starting in 2012, each 

state’s total annual (or ozone season, as applicable) EGU 

emissions would also be capped. Emissions from EGUs in 

each state would be limited to the state’s emissions 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 
514

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 SO2 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 SO2 group 1 states during 2012 and 

2013. 

If total EGU emissions in a state exceed either of

these limits (i.e., budget with 1-year variability limit in 

any year, or budget with 2- or 3-year variability limit on

average), then each company with units in the state whose 

emissions in the state exceeded their share of the state 

budget with variability limit would be subject to a 

penalty. These assurance provisions are designed to assure 

that emissions in each covered state do not exceed the 

state’s budget with variability limit. They are described 

later. EPA also believes the penalty provisions described 
515

later are sufficient to ensure that these caps would not be 

exceeded.

To implement this remedy option, EPA would determine 

unit-level emission rate limits for SO2, NOX annual, and NOX

ozone season at levels such that, if the units operated at 

the levels assumed in determining the state budgets, total 

emissions from these units would sum to each state’s 

emissions budget(s) without the variability limit. The 

method for determining these rate limits is described 

later.

An alternative direct control approach would be to 

create individual unit-level annual emissions caps (e.g., 

tons/year) in order to cap emissions in 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 Emission Rate Limits

To implement this remedy option, EPA would determine 

unit-level emission rate limits for SO2, NOX annual, and NOX
516

ozone season, for covered EGUs in the covered states. 

Emission rate limits would be set at levels such that, if 

the units operated at the levels assumed in determining the 

state budgets, total emissions from these units would sum 

to the state budgets. In a state covered for purposes of 

the PM2.5 NAAQS, EPA would determine SO2 and NOX annual 

emission rate limits for each covered EGU. In a state 

covered for purposes of the 8-hour ozone NAAQS, EPA would 

determine NOX ozone season emission 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 emission 

rate limit on either the unit’s reported annual emissions 

rate or the IPM projected rate. Rates based on reported 

data would be calculated using the most recent 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 
517

available, and projections or source-specific judgments 

otherwise.

For units where EPA is aware that SO2 or NOX controls 

will be installed by 2012 and such controls were not 

reflected in the unit’s reported emission rate as 

determined previously (i.e., the control was not in 

operation during the period of time which emissions limits 

were based upon), EPA would determine the Phase I emission 

rate limit as the historic rate adjusted (reduced) to 

reflect operation of the planned control equipment at an 

emission rate consistent with operation of that equipment. 

Emission rate limits would be determined based on the 

assumption that units operate all existing SO2 and NOX

control equipment, and the assumption that the type of fuel 

used does not change from that used in determining the 

unadjusted rate limit.

For those EGUs which did not report a first, second, 

third, and fourth quarter of SO2, NOX, and/or a complete 

ozone season of NOX emissions data to EPA during the 2007-

2009 period, or for those units located in states where 

budgets are based on IPM projections, EPA would determine 

emission rate limits based on modeling projections. Based 

on the analysis conducted for this proposed rule, EPA would 

use modeling projections to determine SO2 rates for 
518

approximately 1,600 units, annual NOX rates for 1,800 units, 

and ozone season NOX 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 unitlevel 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. 
519

EPA is also taking comment on an alternative approach 

for setting emission rate limits for those units which did 

not report a first, second, third, and fourth quarter of 

SO2, NOX, and/or a complete ozone season of NOX emissions 

data to EPA during the 2007-2009 period. In this 

alternative approach, EPA could develop specific limits 

that would apply to a large group of units with varying 

characteristics. The numerous variables that contribute to 

differences in units’ emissions rates complicate 

development of limits for a large group of units. 

Therefore, to ensure that all units in a broadly-defined 

group could achieve their rate limits, it would be 

necessary to either establish limits that are fairly weak 

so that the poorest-performing units could meet the 

requirements (“lowest-common-denominator” effect), or, 

design more stringent requirements but include provisions 

for exceptions to the requirements. At this time, EPA 

believes using IPM projections and source-specific 

judgments is preferable to the alternative of group-based 

limits, and seeks comments on this alternative.

Emissions rate limits for Phase II (2014 and onward).

For EGUs in states that are in SO2 group 1 (i.e., the more 

stringent SO2 group), EPA would further adjust (reduce) SO2

emission rates for certain EGUs that EPA projects would 
520

install FGD in modeling of the proposed remedy option (at 

less than $2000 per ton); for such units EPA would 

determine emission rate limits at rates consistent with FGD 

operation. For other covered units, Phase II emission rate 

limits would be the same as Phase I limits. Again, 

emission rate limits would be determined based on the 

assumption that units operate all existing SO2 and NOX

control equipment, and that the type of fuel used does not 

change from that used in determining the unadjusted rate 

limit. Note that for ozone season NOX there is only one 

phase.

Emissions rate limits for new units. The emission 

rate limits for covered new units would be set equal to the 

permit rates for these units.

EPA has calculated specific emission rate limits for 

each existing unit that would be covered under this direct 

control remedy option. These unit-level emission rate 

limits appear in a table entitled “Phase I and Phase II 

unit-level emission rate limits” located in the “State 

Budgets, Unit Allocations, and Unit Emissions Rates” TSD in 

the docket for this rulemaking. More detailed description 

of the approach is also provided in the TSD. EPA is 

requesting comment on this approach for determining the 
521

emission rate limits described in the TSD and on the limits 

themselves.

(2) Applicability

Applicability would be the same for all three 

remedies. Refer to section V.D.4 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 exceed the state budget with 1-year 

variability limit in any year (or ozone season, as 
522

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, SO2

emissions from EGUs in group 1 states (i.e., the more 

stringent SO2 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 SO2 group 2 

(i.e., the less stringent SO2 group) and/or states required 

to reduce NOX emissions, EPA would apply only the 1-year 

variability limit in 2012 and 2013, and not the 3-year 

variability limit. Because emissions would be evaluated 

against the 3-year variability limit on a 3-year rolling 

average basis, the application of the 3-year variability 

limit in 2014 would also serve to limit emissions in 2012 

and 2013. For EGUs in SO2 group 1 states (i.e., the more 

stringent SO2 group) EPA would apply a different 1-year SO2

variability limit in 2012 and 2013 than for 2014 and later. 

Furthermore, in these group 1 states, EPA would apply a 2-
523

year SO2 variability limit in 2012 and 2013, and a 3-year 

limit for later years (section IV.F discusses why 

variability limits for the group 1 states would differ in 

2012 and 2013).

If total EGU emissions in a state exceed either the 

state’s budget with 1-year variability limit in any year, 

or budget with 3-year variability limit (or 2-year, as 

appropriate) on average, then each company with units in 

the state whose emissions in the state exceeded its share 

of the state budget with variability limit would be subject 

to a penalty for its share of emissions above the budget 

with variability limit.

In the State Budgets/Limited Trading remedy described 

previously, the proposed assurance provisions include an 

allowance surrender requirement. 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 
524

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 
525

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 SO2 or NOX so does not provide that 

incentive to reduce emissions. Sources can increase 

generation, while meeting the emissions rates limits, and 

increase their emissions. 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 emission rate 

limits for SO2 and/or NOX emission for all of its EGUs. For 

the annual SO2 or NOX control programs, if a company were to

exceed the applicable company-wide annual average rate 
526

limit, it 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 emission rate 

minus the applicable annual average emission rate limit, 

with the difference multiplied by the EGUs’ total actual 

annual heat input. Each ton of excess emissions, as well 

as each day in the averaging period (e.g., 365 days for an 

annual program), would be a violation of the CAA. The 

maximum discretionary penalty under CAA Section 113 is 

$25,000 (inflation-adjusted to $37,500 for 2009) per 

violation.

For the ozone season NOX 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 

SO2, NOX annual or NOX ozone season would also be in 

violation of the CAA and subject to discretionary civil 

penalties explained earlier in this section if, in any year 

(or ozone season, as applicable), the state as a whole 

exceeds its budget with variability limit (see description 

of assurance provisions, previously).

EPA requests comment on the penalty provisions.
527

c. How the 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 

emission rate limits, with company-wide within state 

averaging. Emission rates in all states would be set on a 

unit-by-unit basis at levels such that, if the units 

operated at the levels assumed in determining the state 

budgets, total emissions from these units would sum to each 

state’s emissions budget(s) without the variability limits. 

A company could average the emissions at its units within 

each state to meet specified within-the-state rate limits. 

This approach would directly limit emissions from EGUs in 

each covered state, providing assurance that emission 

reductions would occur within each state consistent with 

the mandate of section 110(a)(2)(D)(i)(I).

Because individual EGUs would be required to meet 

specific emission rate limits (with within-state companywide averaging), this option would ensure that required

controls and measures are installed and implemented within 

the state. The fact that emissions, after implementation 
528

of all controls required to meet the emission 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 SO2 group 1 states during 

2012-2013, a 2-year rolling annual average). Section IV in 

this preamble lists each state’s emissions budget, and 1-, 

2-, and 3-year variability limit, as applicable.
529

d. Electric Reliability 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 emission rate limits and reliably provide 

electricity to customers. EPA requests comment on electric 

reliability issues.

e. Why This is Not the Preferred Option

As explained previously, EPA is requesting comment on

the merits and weaknesses of this direct control remedy 

option. EPA did not include this remedy option in the 

proposed FIPs; however, we continue to consider this option 

and are taking comment on whether this option should be 

included in the FIPs. This option would provide assurance 

that companies in each state are meeting specific emission 

rate limits and would also ensure that annual emissions 

from each state are capped. Additionally, the direct 

control option may be perceived as easy to understand and 

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 
530

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 

that EPA is taking comment on likely mitigates this 

concern. However, this averaging approach may put an owner 

with a small number of units within a state at a 

disadvantage compared to an owner with a larger number of 

units. EPA requests comment on this issue.

Within the direct control approach EPA is taking 

comment on, the assurance provisions (which limit a 

company’s emissions within a state to its share of the 

budget with the variability limit if the state’s budget

with variability limit is exceeded) may also put an owner 

with a small number of units at a disadvantage compared to 
531

an owner with a larger number of units within a state. EPA 

seeks comment on this issue.

A direct control program based on emission rate limits 

does not cap annual emissions; if there is growth in fossil 

generation within a state, a rate-based approach alone 

could allow emissions increases. In the direct control 

approach for which EPA requests comment, the assurance 

provisions provide some assurance of achieving required 

reductions. 

Notably, the direct control approach described herein 

restricts compliance options more than a trading approach. 

EPA generally believes that granting more flexibility to 

companies in meeting an emissions reduction goal results in 

the ability of those companies to meet that goal at a lower 

cost and decreases reliability risks in the electric power 

system. While some portion of this effect is captured in 

IPM modeling (see section V.E. for projected costs and 

emissions), some types of unforeseen innovations in 

technology, fuel switching, and management cannot be 

captured by modeling. Any potential innovations and 

resulting cost savings are more likely to be found and 

utilized in the presence of regulatory flexibility. Based 

on historical experience, EPA believes that the benefits 

offered by a flexible trading approach are large and should 
532

be qualitatively appreciated, even if not quantified. Many 

of these benefits would be foregone under the direct 

control approach.

E. Projected Costs and Emissions for Each Remedy Option

Emission and cost projections for the three remedies 

discussed previously come from the Integrated Planning 

Model (IPM), a dynamic linear programming model of electric 

generation in the contiguous U.S. For each remedy, 

projected costs relative to the 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 EGMTSD.

Table V.E-1 – Projected Incremental Costs Due to Transport 

Rule Remedies Compared to Baseline without Transport Rule 

or CAIR (billion 2006 dollars)

2012 2014 2020 2025

Limited Interstate Trading (proposed) 3.7 2.8 2.0 2.0

Intrastate Trading 4.2 2.7 2.2 2.2

Direct Control 4.3 3.4 2.5 2.3

1. State Budgets/Limited Trading 
533

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 

state-specific emissions limits represent state budgets 

plus 3-year average variability limits. Because banking 

early reductions beyond the budget levels is allowed, 2012 

SO2 reductions are greater overall than state budgets alone 

would require in that year. Table V.E-2 shows the 

projected emissions reductions from this remedy.

Table V.E-2 – Projected SO2 and NOX Electric Generating Unit

Emissions Reductions in Covered States with the Transport 

Rule Compared to Baseline without Transport Rule or CAIR

(million tons)

2012

Base Case

Emissions

2012 

Transport 

Rule

Emissions

2012 

Emissions 

Reductions

2014

Base Case

Emissions

2014 

Transport 

Rule

Emissions

2014

Emissions

Reductions

SO2 8.4 3.4 5.0 7.2 2.6 4.6

Annual 

NOX

2.0 1.3 0.7 2.0 1.3 0.7

Ozone 

Season 

NOX

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 SO2
534

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 SO2

reductions in 2012.

Table V.E-3 – Projected SO2 and NOX Electric Generating Unit

Emissions Reductions in Covered States with the Intrastate 

Trading Alternative Remedy Compared to Baseline without 

Transport Rule or CAIR

(million tons)

2012

Base Case

Emissions

2012 

Transport 

Rule

Emissions

2012 

Emissions 

Reductions

2014

Base Case

Emissions

2014 

Transport 

Rule

Emissions

2014

Emissions

Reductions

SO2 8.4 3.2 5.2 7.2 2.7 4.5

Annual 

NOX

2.0 1.3 0.7 2.0 1.2 0.8

Ozone 

Season 

NOX

0.7 0.6 0.1 0.7 0.6 0.1

3. Direct Control

The direct control alternative remedy consists of 

source-specific emission rate limits commensurate with 

those used in the derivation of state budgets (see sections 
535

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 SO2

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 SO2 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.

Table V.E-4 – Projected SO2 and NOX Electric Generating Unit

Emissions Reductions in Covered States with the Direct 

Control Alternative Remedy Compared to Baseline without 

Transport Rule or CAIR

(million tons)

2012

Base Case

Emissions

2012 

Transport 

Rule

Emissions

2012 

Emissions 

Reductions

2014

Base Case

Emissions

2014 

Transport 

Rule

Emissions

2014

Emissions

Reductions
536

SO2 8.4 3.8 4.6 7.2 2.6 4.6

Annual 

NOX

2.0 1.3 0.7 2.0 1.2 0.8

Ozone 

Season 

NOX

0.7 0.6 0.1 0.7 0.6 0.1

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.

Table V.E-5 – Projected State-level101 SO2 Emissions from 

Electric Generating Units in 2014 (Tons)

Base Case

State 

Budgets/

Limited

Trading

State 

Budgets/

Intrastate 

Trading

Direct 

Control

Alabama 322,362 172,430 162,103 172,430

Connecticut 6,160 3,234 3,208 3,208

Delaware 8,079 9,185 8,974 9,110

District of Columbia 176 179 180 180

Florida 194,723 139,805 159,120 135,366

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 163,966 102,419 102,096 106,569

Kansas 65,125 51,248 52,501 53,275

Kentucky 739,595 123,837 128,318 123,833

Louisiana 94,866 94,933 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

 

101 The modeling presented in Tables V.E-5, V.E-6, and V.E-7 

differs from the proposed Transport Rule because the 

District of Columbia (DC) is included neither in the annual 

SO2 and NOX requirements nor in the ozone season NOX

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.
537

New York 142,762 58,455 53,373 58,455

North Carolina 140,924 97,262 109,385 97,262

Ohio 841,199 232,964 269,547 228,514

Pennsylvania 974,644 154,852 183,276 154,855

South Carolina 156,200 131,232 123,525 131,232

Tennessee 600,071 106,767 100,012 94,078

Virginia 136,573 58,329 51,633 58,330

West Virginia 496,307 127,646 147,580 127,646

Wisconsin 117,397 85,933 87,328 83,709

Table V.E-6 – Projected State-level Annual NOX Emissions 

from Electric Generating Units in 2014 (Tons)

Base Case

State 

Budgets/

Limited 

Trading

State 

Budgets/

Intrastate 

Trading

Direct 

Control

Alabama 118,955 61,793 61,618 61,865

Connecticut 7,991 8,003 7,986 8,004

Delaware 5,790 6,176 6,126 6,074

District of Columbia 933 946 948 948

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 52,069

Kansas 79,018 40,020 40,074 39,558

Kentucky 148,551 71,371 71,692 69,882

Louisiana 45,551 37,255 36,594 37,164

Maryland 36,089 36,326 33,778 36,532

Massachusetts 12,650 13,047 12,219 13,064

Michigan 98,941 65,066 65,973 67,525

Minnesota 55,283 38,969 39,114 38,039

Missouri 83,019 67,475 61,679 67,648

Nebraska 53,029 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

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 37,004

West Virginia 100,095 48,180 48,987 50,555

Wisconsin 54,515 41,875 42,498 42,450
538

Table V.E-7 – Projected State-level Ozone-season NOX

Emissions from Electric Generating Units in 2014 (Tons)

Base Case

State 

Budgets/

Limited 

Trading

State 

Budgets/

Intrastate 

Trading

Direct 

Control

Alabama 26,995 26,727 26,552 26,823

Arkansas 21,667 12,080 12,095 12,077

Connecticut 3,446 3,453 3,446 3,446

Delaware 2,367 2,669 2,671 2,613

District of Columbia 391 397 397 398

Florida 94,686 62,221 62,037 48,170

Georgia 21,947 19,686 19,688 19,749

Illinois 24,167 24,930 22,833 24,701

Indiana 49,023 47,477 47,813 45,589

Kansas 34,537 17,470 17,590 17,282

Kentucky 29,927 29,376 29,671 29,107

Louisiana 21,443 17,388 17,106 17,308

Maryland 15,307 15,454 14,275 15,512

Michigan 29,934 27,778 28,052 29,415

Mississippi 16,955 8,524 8,526 8,522

New Jersey 10,470 10,324 10,295 10,260

New York 17,257 17,493 16,518 17,491

North Carolina 27,018 26,117 23,459 26,004

Ohio 44,753 41,141 40,051 42,789

Oklahoma 38,546 24,471 24,471 24,426

Pennsylvania 53,263 53,102 52,692 52,586

South Carolina 15,730 14,818 14,666 14,753

Tennessee 12,021 11,868 10,955 12,007

Texas 79,572 68,769 68,874 67,832

Virginia 16,264 15,397 15,289 16,093

West Virginia 24,339 20,249 21,466 21,500

F. Transition from the CAIR 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.
539

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 
540

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 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 
541

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 post2011 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 
542

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 
543

(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 previously-described, proposed 

revisions to §§51.123, 51.124, 52.35, and 52.36, certain 
544

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 
545

from the NOX Budget Trading Program to the CAIR NOX ozone 

season trading program, EPA will work with states to 

transition from state CAIR programs to their replacement 

FIPs or state SIPs. This assistance will be provided 

through meetings or workshops, web-based references, 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 state-specific 

Part 52 provision adopting a CAIR FIP -- whether for NOX

annual or ozone season emissions or SO2 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 
546

Transport Rule the proposed rule text making these stateby-state revisions for Delaware, District of Columbia, 

Indiana, Louisiana, Michigan, New Jersey, Tennessee, Texas, 

and Wisconsin. These provisions revise all of the statespecific Part 52 provisions adopting CAIR FIPs provisions 

to make the CAIR FIPs inapplicable to any control period 

that starts after December 31, 2011 and state that the 

Administrator would not carry out any functions under the 

CAIR trading programs during any such control period and 

would not use any CAIR allowances allocated for any such 

control period. 

2. Change in States Covered

The states covered by the proposed Transport Rule 

differ slightly from states covered by the CAIR. Namely, 

as compared with the states covered by the CAIR NOX ozone 

season trading program, the states covered by the proposed 

Transport Rule NOX 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 NOX

annual and SO2 trading programs, the states covered by the 

proposed Transport Rule NOX Annual and SO2 trading programs

would include Connecticut, Kansas, Massachusetts, 

Minnesota, and Nebraska and would not include Mississippi 
547

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 NOX 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 
548

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 NOX SIP Call was allowed to expand the 

applicability of the CAIR NOX ozone season trading program 

in the state in order to include all units subject to the 

NOX Budget Trading Program (NBP) under the NOX SIP Call and 

thereby to continue to meet the state’s NOX SIP Call 

requirements. Fourteen states chose to expand the CAIR NOX

ozone season applicability in this way, while six states 

chose not to expand the applicability and instead to meet 

their NOX SIP Call obligations in other ways. In expanding 

the applicability of the CAIR NOX 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 NOX ozone season budgets in these states were increased 

to account for these additional sources. In contrast, the 
549

proposed Transport Rule NOX 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 NOX

SIP Call (i.e., Massachusetts, Missouri, and Rhode Island). 

Further, the six states that chose under the CAIR to 

require the necessary NOX SIP Call reductions through 

provisions other than the CAIR NOX ozone season program 

would not likely be interested in expanding applicability 

under the Transport Rule NOX ozone season trading program to 

cover these units. In addition, EPA has determined that 

these units as a group did not actually reduce emissions as 

a result of the NBP or through their inclusion in the CAIR 

NOX ozone season trading program. In fact, their current 

emission rates are nearly 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 
550

expand applicability to include them. EPA is taking 

comment on this approach.

4. Early Reduction Provisions

Substantial emission reductions have occurred as a 

result of the CAIR programs. These 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. SO2 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 emission reductions for Title IV where allowances are 

used for compliance with the requirement to hold allowances 

covering emissions and early reductions for the CAIR SO2

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 SO2 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 SO2 program in 
551

any way. One idea presented to EPA was to distribute 

Transport Rule SO2 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 SO2 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 because the number of Title IV allowances in a 

source’s account may not be directly related to the section 

110(a)(2)(D)(i)(I) mandate to eliminate significant 

contribution. EPA chose instead, under the proposed 

Transport Rule, to distribute allowances in a manner 

directly linked to its calculation of each state’s 

significant contribution and interference with maintenance. 

EPA is confident that the approach selected is consistent 

with the Court’s opinion in North Carolina v. EPA, 531 F.3d 

896, 922 (D.C. Cir. 2008). (Additional information on this 

approach can be found in the docket.) EPA requests comment 

on whether or not an allowance 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 SO2 allowances or directly for 
552

compliance with allowance-holding requirements. Thus,

there would be no SO2 allowances carried over into the new 

SO2 program. Title IV allowances continue, of course, to be 

used for compliance with the Acid Rain Program.

b. NOX Allowance Banks

Assuming that NOX emissions in 2010 and 2011 are equal 

to what they were in 2009, the CAIR NOX 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 NOX ozone season program 

for 2012), and the CAIR NOX annual bank would contain over 

270,000 allowances (which would equal about 20 percent of 

the total of the state budgets under the proposed Transport 

Rule NOX annual program for 2012), after completion of trueup 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 these approaches. On one hand, 

allowing pre-2012 CAIR NOX allowances and CAIR NOX ozone 

season allowances to be used in the proposed Transport Rule 

NOX programs, and thereby ensuring that the allowances would 

continue to have some market value in the future, would 
553

promote the continuation -- in 2010 and 2011 -- of the 

reductions that occurred in 2009 under the CAIR NOX

programs. On the other hand, the amounts of the banks are 

so large that they might significantly reduce the amount of 

emission reductions that would otherwise be achieved in the 

proposed Transport Rule NOX programs, particularly in the 

earlier years (e.g., 2012 and 2013). 

EPA has identified several possible approaches for 

handling banked pre-2012 CAIR NOX allowances in the 

Transport Rule NOX programs. The first approach might be to 

allow all such banked CAIR allowances to be brought into 

the Transport Rule NOX 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 NOX programs. However, EPA is 

concerned about the legal risk of this approach. 

Specifically, this approach might be viewed 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 
554

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 NOX 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 NOX

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 emission 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 NOX 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 
555

be feasible because EPA cannot determine in advance in 

which states banked pre-2012 CAIR allowances might be used 

and so would not know which state budgets should be 

adjusted and what amount of adjustment would be necessary. 

A final approach would simply be to not allow the use 

of any banked pre-2012 CAIR allowances in the Transport 

Rule NOX programs. This approach would avoid the potential 

legal and practical problems raised by the other approaches 

and is the approach proposed by EPA. EPA requests comment 

on the proposed approach, the previously-discussed 

alternative approaches, and any other possible approaches 

for handling banked pre-2012 CAIR allowances in the 

Transport Rule NOX 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 NOX ozone season 

requirements but NOX and SO2 annual requirements under the 
556

proposed Transport Rule; or CAIR states subject to CAIR NOX

annual and ozone season and SO2 requirements but only to NOX

ozone season requirements under the proposed Transport 

Rule. These exceptions could arise, in part, because under 

40 CFR Part 75 some units (i.e., non-Acid Rain units) that 

are in NOX ozone season, and not NOX annual, programs have 

the option of monitoring and reporting NOX emissions for 

just the ozone season. 

Units in the following states monitor and report both 

SO2 and NOX year-round under the CAIR and would continue to 

do so under the Transport Rule: Alabama, Delaware, the 

District of Columbia, Florida, Georgia, Illinois, Indiana, 

Iowa, Kentucky, Louisiana, Maryland, Michigan, Missouri, 

New Jersey, New York, North Carolina, Ohio, Pennsylvania, 

South Carolina, Tennessee, Virginia, West Virginia, and 

Wisconsin. Non-Acid Rain units in Arkansas are currently 

required to monitor and report NOX in the ozone season under 

the CAIR and would continue to be required to do so under 

the proposed Transport Rule. 

Non-Acid Rain units in Connecticut and Massachusetts

(about 15 units total) that currently monitor and report NOX

in the ozone season would need to monitor and report NOX and 

SO2 on an annual basis under the proposed Transport Rule.
557

Non-Acid Rain units in Mississippi (about 4 units) and 

Texas (about 52 units) are currently monitoring and 

reporting NOX and SO2 year-round and under the proposed 

Transport Rule would be required to monitor and report NOX

in the ozone season. (All of these units burn natural gas 

and emitted approximately 12 tons of SO2 in 2009.)

In states not covered by the CAIR but covered by the 

proposed Transport Rule, some units would have to meet new 

monitoring and reporting requirements under 40 CFR Part 75. 

Kansas, Minnesota, and Nebraska are not covered by the CAIR 

and are covered by the Transport Rule, and units there 

would need to monitor and report NOX and SO2 emissions yearround. Oklahoma is not covered by the CAIR and is covered 

by the Transport Rule, and units there would need to 

monitor and report NOX in the ozone season. There are about 

34 non-Acid Rain units total in Kansas, Nebraska and 

Oklahoma not monitoring and reporting under 40 CFR Part 75 

that would need to begin to do so. Most of these units are 

simple-cycle 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 
558

already monitoring and reporting under 40 CFR Part 60, 

subpart Da, which requires an SO2, NOX 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 40 CFR 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 NOX SIP 

Call 

1. Title IV Interactions

Promulgation of a Transport Rule would not affect any 

Acid Rain Program requirements. Any Title IV sources that 
559

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 SO2

allowances to be used in the Transport Rule program. 

Similarly, Transport Rule SO2 allowances would not be 

useable in the Acid Rain Program. Title IV SO2 and NOX

requirements will continue to apply independently of the 

Transport Rule provisions. The Transport Rule program as 

proposed has no opt-in provisions, so no sources, including 

any that have opted into the Acid Rain program would be 

able to opt-in to the Transport Rule program.

Compliance with the Transport Rule would reduce SO2

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 
560

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, 

SO2 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. NOX SIP Call Interactions

States affected by both the NOX SIP Call and any final 

Transport Rule will be required to comply with the 

requirements of both rules. The Transport Rule does not 

preempt or replace the requirements of the NOX SIP Call. 

However, the proposed Transport Rule ozone season program 

would achieve the emissions reductions required by the NOX

SIP Call from EGUs greater than 25 MW in nearly all NOX SIP 

Call states. The NOX SIP Call states used the NOX Budget 
561

Trading Program (NBP) to comply with the NOX SIP Call 

requirements for EGUs greater than 25 MW and large non-EGUs 

with a maximum rated heat input capacity greater than 250 

MMBTU/hr. (In some states, EGUs smaller than 25 MW were 

also part of the NBP as a carryover from the Ozone 

Transport Commission NOX 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 NOX SIP Call requirements.

Many of the states using the NBP used the CAIR NOX

ozone season trading program to replace the NBP. To 

address NOX SIP Call requirements, fourteen NOX SIP Call 

states chose to expand the CAIR NOX ozone season 

applicability to include all NBP-affected units. EPA has 

analyzed the effect of allowing states to expand their CAIR 

NOX ozone season applicability and consequently their CAIR 

NOX ozone season budgets to include the additional non-CAIR 

affected NBP units. In 2009, the additional units emitted 

about half of the amount of allowances added to the CAIR NOX

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 NOX

emissions or their NOX emission rates as a result of their 

inclusion in the CAIR NOX ozone season program. If EPA were 
562

to allow them to be part of the Transport Rule NOX Ozone 

Season Program, and if states were allowed to increase the 

Transport Rule NOX 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 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 

NOX SIP Call emission reductions another way in order to 

continue to comply with the NOX SIP Call. If EPA 
563

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 NOX Ozone Season 

Program would need to submit a SIP revision to address 

their NOX SIP Call requirement for the reductions.

States that were part of the CAIR NOX 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 NOX SIP Call requirements for any 

emission reductions that were part of either the CAIR NOX

ozone season program or the NBP and would not continue to 

be addressed some other way. EPA will work with states to 

ensure that NOX 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 
564

assure accuracy. Subsequent to these sessions, EPA 

received post-meeting comments and additional detailed 

suggestions and analyses on ways to address some of the 

issues that the court cited, most notably from state 

regional organizations in the eastern U.S. All the 

stakeholder-related materials may be found in the EPA 

docket for the transport rule (OAR-2009-0491). 

Following the remand of CAIR to EPA in December 2008, 

17 states in the East and Midwest, under the umbrellas of 

the OTC and Lake Michigan Air Directors Consortium (LADCO) 

with support from southeastern states, worked to develop 

recommendations for EPA to consider in crafting a new 

transport rule to replace CAIR. The comprehensive 

framework presented the consensus approach the states 

reached but noted that certain regional differences would 

be addressed in separate letters with additional 

recommendations and supporting materials.

EPA 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: 
565

 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 SO2 emissions reductions 

requirements

• Threshold (1 percent of the NAAQS) used for linking 

upwind areas to downwind nonattainment and maintenance 

receptors
566

• 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 

PM2.5 NAAQS

All states have an obligation to submit SIPs that 

address the requirements of CAA section 110(a)(2) within 3 

years of promulgation or revision of a NAAQS. With respect 

to the 1997 ozone and PM2.5 NAAQS, EPA found in 2005 that 

states had failed to make submissions that address the 

requirements of section 110(a)(2)(D)(i) related to 

interstate transport of pollution. See 70 FR 21147 (April 

25, 2005). 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) 
567

obligations. In the CAIR, EPA concluded that the States in 

the CAIR region would meet their section 110(a)(2)(D)(i) 

obligations to address “significant contribution” and “ 

interference with maintenance” requirements by complying 

with the CAIR requirements. Consequently, states within 

the CAIR region did not need to submit a separate SIP 

revision to 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 
568

110(a)(2)(D)(i)(I)102 remain in force regardless of whether 

a state covered by the CAIR submitted and/or had an 

approved SIP stating that compliance with the CAIR 

satisfied their 110(a)(2)(D)(i) obligations. 

The 2005 findings of failure to submit also remain in 

force for many states not covered by the original CAIR. 

Some of these states have not yet submitted 

110(a)(2)(D)(i)(I) SIPs and thus the findings remain in 

force. However, several states that were not covered by 

the CAIR have since 2005 submitted SIP revisions to satisfy 

the requirements of section 110(a)(2)(D)(i) for the 1997 8-

hour ozone and PM2.5 NAAQS. Some of these SIPs have been 

approved and some are pending approval.

For the states that have now been identified to be 

contributing significantly to nonattainment or interfering 

with maintenance under this proposed rule and whose 

110(a)(2)(D)(i)(I) SIPs with respect to the 1997 ozone and 

PM2.5 NAAQS are pending approval, EPA will finalize the FIP 

included in this proposed rule only if EPA either 

determines that the SIP submission is incomplete or 

 

102 The 2005 findings of failure to submit related to 

state’s 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).
569

disapproves the SIP submission. (Alternatively, if a state 

withdraws its SIP submission, EPA will finalize the FIP.)

For states which are not included in a final FIP under 

this proposed transport rule and that have not submitted a

110(a)(2)(D)(i)(I) SIP to address the 1997 ozone and PM2.5

NAAQS, a SIP submittal is required.

EPA has approved the 110(a)(2)(D)(i) submission from 

the state of Kansas for the 1997 ozone and PM2.5 NAAQS. The 

updated modeling done for this proposed rule demonstrates 

that emissions from Kansas significantly contribute to 

nonattainment or interfere with maintenance of the 1997 8-

hour ozone NAAQS in downwind areas. Because Kansas’ 

current SIP does not prohibit these emissions, it is not 

adequate to satisfy the requirements of 110(a)(2)(D)(i)(I) 

at this time. For Kansas, under a separate action, EPA 

plans to propose a finding under CAA 110(k)(5) (known as a 

SIP Call) that the state’s existing SIP is substantially 

inadequate to meet the requirements of 110(a)(2)(D)(i)(I) 

with respect to the 1997 ozone NAAQS. That SIP 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 
570

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 PM2.5

NAAQS

With respect to the 2006 24-hour PM2.5 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 PM2.5

NAAQS have been acted on yet by EPA. For the states with 

SIPs that are pending approval, EPA is proposing to 

finalize the FIP with respect to the 2006 PM2.5 NAAQS only 

if EPA finds the previously submitted SIP incomplete or 

disapproves the SIP submission. Alternatively, if any of 

these states withdraws its 2006 24-hour PM2.5 SIP submittal, 

EPA plans to issue a separate notice of finding for such 

states.

C. Transport Rule SIPs

EPA also notes that, by promulgating this Transport 

Rule FIP, EPA is in no way affecting the right of states to 

submit, for review and approval, a SIP that replaces the 

federal requirements of the FIP with state requirements. 

The SIP must provide adequate provisions to prohibit NOX and 
571

SO2 emissions that contribute significantly to nonattainment 

or interfere with maintenance in another state or states. 

EPA is taking comment on how a state could replace the FIP 

with a SIP and what the SIP approval criteria should be.

VIII. Title V Permitting

EPA’s proposed FIPs would not establish any permitting 

requirements independent of those under Title V of the CAA 

and the regulations implementing Title V, 40 CFR Parts 70 

and 71103. 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. 

 

103 Part 70 governs approved state Title V programs, and 

Part 71 governs the federal Title V program. 
572

For example, requirements under the proposed FIPs 

concerning designated 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. 

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 marketbased 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, 
573

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 
574

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). 
575

As new applicable requirements under Title V, the 

requirements for covered units under the final FIPs would 

be incorporated into covered sources’ existing Title V 

permits either pursuant to the provisions for 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))104. For 

sources newly subject to title V that would also be covered 

sources under the proposed FIPs, the initial Title V permit 

issued pursuant to 40 CFR 70.7(a) would include the final 

FIP requirements. In order to ensure that covered sources’ 

Title V permit provisions concerning the FIPs would 

reflect, properly and in a manner consistent from permit to 

permit, the trading program requirements and flexibilities, 

EPA intends to issue guidance, after promulgation of the 

final FIPs, to assist permitting authorities. This 

guidance would include information on permit issuance and 

permit modification requirements, as well as a permit 

content template that would identify the applicable 

requirements under the trading program and thereby ensure 

 

104 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).
576

that they would be correctly and comprehensively reflected 

in each permit in a manner that would reduce the need for 

frequent permit revisions. Use of a permit 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.

IX. What benefits are projected for the proposed rule?

In this section, we present the results of EPA’s

analysis of the benefits of the emissions reductions in 

this proposal on PM2.5 and ozone air quality, public health, 

welfare, and the environment. These improvements were 

determined based upon air quality modeling of the 2014 base 

case and the “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 PM2.5 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 
577

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 PM2.5 co-benefits is 

largely driven by the concentration-response function for 

premature mortality, we examined alternate relationships 

between PM2.5 and premature mortality supplied by experts. 

Higher and lower co-benefits estimates are plausible, but 

most of the expert-based estimates fall between these two 

estimates above.105 All monetized estimates are stated in 

2006 dollars. Also note that the analytic baseline 

presents a unique situation. EPA has been directed to 

replace the CAIR; yet the CAIR remains in place and has led 

to significant 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 

 

105 Roman et al, 2008. Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate 

Matter in the U.S. Environ. Sci. Technol., 42, 7, 2268 –

2274.
578

affected by the rule. For example, a state affected by 

CAIR may not be affected by the new rule and after the new 

rule goes into effect, the CAIR requirements will no longer 

apply. For a state covered by 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 NOX program 

will lead to the status quo of the NOX Budget Program, which 

limits ozone-season NOX emissions and ensures the operation 

of NOX controls in those states. Also, without the CAIR SO2
579

program, emission requirements in many areas would revert 

to the comparatively less stringent requirements of the 

Title IV Acid Rain program. As a result, SO2 emissions in 

many states would increase markedly in the 2012 base case 

relative to the present. Efforts to comply with ARP rules 

at the least-cost would occur in many cases without the 

operation of existing scrubbers through use of readily 

available, inexpensive Title IV allowances. Notably, all 

known controls that are required under state laws, NSPS, 

consent decrees, and other enforceable binding commitments 

through 2014 are accounted for in the base case. It is 

against this backdrop that the Transport Rule is analyzed 

and that significant contribution to nonattainment and 

interference with maintenance must be addressed.

A. The Impacts on PM2.5 and Ozone of the Proposed SO2 and NOX

Strategy

The air quality modeling platform described in section 

IV.C. was used by EPA to model the impacts of the proposed 

SO2 and NOx emissions reductions on annual average PM2.5, 24-

hour PM2.5, and 8-hour ozone concentrations. In brief, we 

ran the CAMx model for the meteorological conditions in the 
580

year of 2005 for the Eastern U.S. modeling domain106. 

Modeling was performed for the 2014 base case and the 2014 

“State Budgets/Limited Trading” scenario to assess the 

expected effects of the proposed regional strategy on 

projected PM2.5 and ozone design value concentrations and 

nonattainment and maintenance. The procedures used to 

project future design values and nonattainment and 

maintenance are described in section IV.C. The aggregate 

emissions in 2012 and 2014 for SO2 and NOX 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 PM2.5, daily 

PM2.5, 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 PM2.5, daily PM2.5, and ozone are provided 

in Table IX-1

107. The average and peak reductions in annual 

 

106 As described in the AQMTSD, the Eastern U.S. was modeled 

at a horizontal resolution of 12 x 12 km. The remainder of 

the U.S. was modeled at a resolution of 36 x 36 km.

107 To provide a point of reference, Table IX-1 also 

includes the number of nonattainment and/maintenance sites 

based on ambient design values for the period 2003 through 

2007.
581

PM2.5, daily PM2.5, and ozone predicted at 2012 nonattainment 

and/or maintenance sites due the emissions reductions 

between 2012 and the 2014 remedy are provided in Table IX2. 

TABLE IX-1. PROJECTED REDUCTION IN NONATTAINMENT AND/OR 

MAINTENANCE PROBLEMS FOR PM2.5 AND OZONE IN THE EASTERN U.S.

Ambient

(2003-

2007)

2012 

Base 

Case

2014 

Base 

Case

2014 

Proposed 

Remedy

Percent 

Reduction

: 2012 

Base Case 

vs. 2014 

Remedy

Percent 

Reduction

: 2014 

Base Case 

vs. 2014 

Remedy

Annual PM2.5 

Nonattainment 

Sites108

102 32 15 1 97% 93%

Annual PM2.5 

MaintenanceOnly Sites

21 16 7 1 94% 86%

Daily PM2.5 

Nonattainment 

Sites

151 92 54 17 82% 69%

Daily PM2.5 

MaintenanceOnly Sites

48 38 28 11 71% 61%

Ozone 

Nonattainment 

Sites

103 11 7 7 36% 0%

Ozone 

MaintenanceOnly Sites

67 16 6 5 69% 17%

TABLE IX-2. AVERAGE AND PEAK REDUCTION IN ANNUAL PM2.5, 

DAILY PM2.5, AND OZONE FOR SITES THAT ARE PROJECTED TO HAVE 

NONATTAINMENT AND/OR MAINTENANCE PROBLEMS IN THE 2012 BASE 

CASE

 

108 “Nonattainment” is used to denote sites that are 

projected to have both nonattainment and maintenance 

problems.
582

Average 

Reduction: 

2012 Base 

Case to 

2014 

Remedy

Peak 

Reduction: 

2012 Base 

case to 

2014 

Remedy

Annual PM2.5 

Nonattainment Sites 2.8 μg/m3 3.9 μg/m3

Annual PM2.5 

Maintenance-Only Sites 2.6 μg/m3 4.2 μg/m3

Daily PM2.5 

Nonattainment Sites 5.8 μg/m3 15.3 μg/m3

Daily PM2.5 

Maintenance-Only Sites 5.1 μg/m3 13.5 μg/m3

Ozone Nonattainment 

Sites 1.9 ppb 3.9 ppb

Ozone Maintenance-Only 

Sites 2.3 ppb 4.2 ppb

The information in Table IX-1 shows that there will be 

significant reductions in the extent of nonattainment and 

maintenance problems for annual PM2.5, daily PM2.5, and ozone 

between 2012 and 2014 as a result of the emissions budgets 

in this proposal coupled with emissions reductions during 

this time period from 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 PM2.5 in 2014 with the 

emissions reductions expected from today’s proposal. As 
583

indicated in Table IX-2, the average reduction in annual

PM2.5 across the 32 2012 nonattainment sites is 1.9 μg/m3 and 

the peak reduction at an individual nonattainment site is 

3.2 μg/m3. Comparable reductions are projected at annual

PM2.5 maintenance-only sites. 

For 24-hour PM2.5, we project that the number of 

nonattainment sites will be reduced by 82 percent and the 

number maintenance-only sites by 71 percent in 2014 

compared to the 2012 base case. The average reduction in 

24-hour PM2.5 across the 92 2012 nonattainment sites is 5.8 

μg/m3 and the peak reduction at an individual nonattainment 

site is 15.3 μg/m3. Comparable reductions are projected at 

24-hour PM2.5 maintenance-only sites. 

The emissions reductions in today’s proposal will 

result in considerable progress toward attainment and 

maintenance at the 28 sites that remain as nonattainment 

and/or maintenance for the 24-hour the PM2.5 standard. On 

average for these 28 sites, the predicted amount of PM2.5

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 SO2 and NOX emissions reductions which will 

result from today’s proposal will greatly reduce the extent 

of PM2.5 nonattainment and maintenance problems by 2014 and 

beyond. As described above, these emissions reductions are 
584

expected to substantially reduce the number of PM2.5

nonattainment and/or maintenance sites in the East and make 

attainment easier for those counties that remain 

nonattainment by substantially lowering PM2.5 concentrations.

in residual nonattainment sites. The emissions reductions 

will also help those locations that may have maintenance 

problems.

Based on the 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 NOX reductions in today’s proposal 

are projected to lower 8-hour ozone concentration by 2.8

ppb, on average by 2014, at monitoring sites projected to 

be nonattainment and/or have maintenance problems in the 

2012 base case. We expect that the number of nonattainment 

sites will be reduced by 36 percent and the number 

maintenance-only sites by 69 percent in 2014 compared to 

the 2012 base case. For the 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 NOX emissions reductions in this

proposal will lower ozone concentrations in the East and 
585

help bring areas closer to attainment for the 8-hour ozone 

NAAQS.

B. Human Health Benefit Analysis

To estimate the human health benefits of the proposed 

Transport Rule, we used the BenMAP model to quantify the 

changes in PM2.5 and ozone-related health impacts and 

monetized benefits based on changes in air quality. We 

provide such estimates for the proposed remedy option.

Notably, EPA expects that in 2014 the other two 

alternatives that the Agency considered have the same 

general level of benefits that will result from their 

implementation. The results of the analysis for the 

alternate SO2 reduction scenarios are found in the RIA. For 

context, it is important to note that the magnitude of the 

PM2.5 benefits is largely driven by the concentration 

response function for premature mortality. Experts have 

advised EPA to consider a variety of assumptions, including 

estimates based both on empirical (epidemiological) studies 

and judgments elicited from scientific experts, to 

characterize the uncertainty in the relationship between 

PM2.5 concentrations and premature mortality. For this 

proposed rule we cite two key empirical studies, one based 
586

on the American Cancer Society cohort study109 and the other 

based on the extended Six Cities cohort study.110 

Table IX–3 presents the primary estimates of reduced 

incidence of PM2.5 and ozone-related health effects in 2014 

for the proposed and alternative remedies. In 2014, we 

estimate that PM-related annual benefits of the proposed 

remedy include approximately 14,000 to 36,000 fewer 

premature mortalities, 9,200 fewer cases of chronic 

bronchitis, 22,000 fewer non-fatal heart attacks, 11,000 

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 

 

109 Pope et al, 2002. “Lung Cancer, Cardiopulmonary 

Mortality, and Long-term Exposure to Fine Particulate Air 

Pollution.” Journal of the American Medical Association 

287:1132-1141.

110 Laden et al, 2006. “Reduction in Fine Particulate Air 

Pollution and Mortality.” American Journal of Respiratory 

and Critical Care Medicine. 173: 667-672.
587

SO2 controls in the proposed remedy because the baseline has 

much greater controls resulting from State actions and 

consent decrees.

Ozone health-related benefits are expected to occur 

during the summer ozone season (usually ranging from May to 

September in the Eastern U.S.). Based upon modeling for 

2014, annual ozone related health benefits are expected to 

include between 50 and 230 fewer premature mortalities, 690

fewer hospital admissions for respiratory illnesses, 230

fewer emergency room admissions for asthma, 300,000 fewer 

days with restricted activity levels, and 110,000 fewer 

days where children are absent from school due to 

illnesses. When adding the PM and ozone-related 

mortalities together, we find that the proposed Transport 

Rule will yield between 14,000 and 36,000 fewer premature 

mortalities. The following references are used in 

providing our estimates of ozone health-related benefits:

Bell, M.L., et al. 2004. Ozone and short-term mortality in 

95 US urban communities, 1987-2000. Journal of the 

American Medical Association. 292(19): p. 2372-8.

Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 

2006. Reduction in Fine Particulate Air Pollution and 

Mortality. American Journal of Respiratory and Critical 

Care Medicine 173:667-672. Estimating the Public Health 

Benefits of Proposed Air Pollution Regulations. 

Washington, DC: The National Academies Press.

Levy JI, Baxter LK, Schwartz J. 2009. Uncertainty and 

variability in health-related damages from coal-fired 
588

power plants in the United States. Risk Anal. doi: 

10.1111/j.1539-6924.2009.01227.x [Online 9 Apr 2009]

Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. 

Krewski, K. Ito, and G.D. Thurston. 2002. Lung Cancer, 

Cardiopulmonary Mortality, and Long-term Exposure to Fine 

Particulate Air Pollution. Journal of the American 

Medical Association 287:1132-1141.

TABLE IX–3.—ESTIMATED ANNUAL REDUCTIONS IN INCIDENCE OF 

HEALTH EFFECTSA

Health Effect Proposed remedy

PM-Related endpoints

Premature Mortality

Pope et al. (2002) (age 

>30)

14,000

(4,000—25,000)

Laden et al. (2006) 

(age >25)

36,000

(17,000—56,000)

Infant (< 1 year) 59

(-66—180)

Chronic Bronchitis 9,200

(320—18,000)

Non-fatal heart 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)
589

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)

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 
590

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 CO2 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 CO2 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 CO2 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-HQOAR-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 
591

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. 

TABLE IX–4.—ESTIMATED ANNUAL MONETARY VALUE OF REDUCTIONS 

IN INCIDENCE OF HEALTH AND WELFARE EFFECTS (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 PM2.5 & O3

$110

($8.8—$340)

7% discount rate PM2.5 & O3

$100

($7.9—$300)

Premature mortality (Laden et al. 2006 PM mortality and 

Levy et al. 2005 ozone mortality estimates)

3% discount rate PM2.5 & O3

$280

($25—$820)

7% discount rate PM2.5 & O3

$260

($22—$310)

Chronic Bronchitis PM2.5

$4.3

 ($0.2—$20)

Non-fatal heart attacks 

3% discount rate PM2.5

$2.5

($0.4—$6)

7% discount rate PM2.5

$2.4

($0.4—$5.9)

Hospital admissions—

respiratory PM2.5 & O3

$0.06

($0.03—$0.1)

Hospital admissions—

cardiovascular PM2.5

$0.2

($0.1—$0.3)
592

Emergency room visits for 

asthma PM2.5 & O3

$0.005

($0.002—$0.008)

Acute bronchitis PM2.5

$0.009

(-$0.0004—$0.03)

Lower respiratory symptoms PM2.5

$0.005

($0.002—$0.009)

Upper respiratory symptoms PM2.5

$0.006

($0.001—$0.014)

Asthma exacerbation PM2.5

$0.012

($0.001--$0.046)

Lost work days PM2.5

$0.2

($0.19—$0.24)

School loss days

$0.01

($0.004—$0.013)

Minor restricted-activity 

days PM2.5 & O3

$0.64

($0.34—$0.97)

Recreational visibility, 

Class I areas PM2.5 $3.6

Total benefits based on Pope et al. 2002 PM mortality and 

Bell et al. 2004 ozone mortality estimates

3% discount rate PM2.5 & O3

$120

($10—$360)

7% discount rate PM2.5 & O3

$110

($9—$330)

Total benefits based on Laden et al. 2006 PM mortality and 

Levy et al. 2005 ozone mortality estimates

3% discount rate PM2.5 & O3

$290

($26—$840)

7% discount rate PM2.5 & O3

$270

($24—$760)

A Estimates rounded to two significant figures

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 
593

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 
594

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, 
595

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.

TABLE IX–5.—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET 

BENEFITS OF THE TRANSPORT RULE IN 2014

[Billions of 2006 dollars]

Description Proposed remedy

Social costs 

3 percent discount rate $2.0

7 percent discount rate 2.2
596

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 NOX and SO2 in the Transport Rule region.

c As this table indicates, total benefits are driven primarily by 

PM2.5-related health benefits. The reduction in premature 

fatalities each year accounts for over 90 percent of total 

monetized benefits 2014. Benefits in this table are nationwide

(with the exception of visibility) and are associated with NOX

and SO2 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.

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 
597

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 
598

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 benefitcost 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 $6.3 million (2000$).111 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: 

 

111 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. 
599

(1) EPA assumes inhalation of fine particles is 

causally associated with premature death at 

concentrations near those experienced by most 

Americans on a daily basis. Plausible biological 

mechanisms for this effect have been hypothesized for 

the endpoints included in the primary analysis and the 

weight of the available epidemiological evidence 

supports an assumption of causality.

(2) EPA assumes all fine particles, regardless of

their chemical composition, are equally potent in 

causing premature mortality. This is an important 

assumption, because the proportion of certain 

components in the PM mixture produced via precursors 

emitted from EGUs may differ significantly from direct 

PM released from automotive engines and other 

industrial sources, but no clear scientific grounds 

exist for supporting differential effects estimates by 

particle type.

(3) We assume that the health impact function for fine 

particles is linear down to the lowest air quality 

levels modeled in this analysis. Thus, the estimates 

include health benefits from reducing fine particles 

in areas with varied concentrations of PM2.5, including 

both regions that are in attainment with fine particle 
600

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 

PM2.5 and ozone in the Eastern United States are expected to 

occur from this rule. These other benefits occur both 

directly from NOX and SO2 emissions reductions. These 

benefits are listed in Table IX–6. Some of the more 
601

important examples include: Reductions in NOX and SO2

emissions required by the Transport Rule will reduce 

acidification and, in the case of NOX, 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 SO2 and 

NOX react in the atmosphere (with water, oxygen, and 

oxidants) to form various acidic compounds. These acidic 

compounds fall to earth in either a wet form (rain, snow, 

and fog) or a dry form (gases and particles). Prevailing 

winds can transport acidic compounds hundreds of miles, 

across State borders. Together these emissions are 
602

deposited onto terrestrial and aquatic ecosystems across 

the U.S., contributing to the problems of acidification, 

nutrient enrichment, and methylmercury production. In 

addition, NOx 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 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, 
603

watersheds that contain alkaline minerals, such as 

limestone, tend to have waters with a high ANC. Areas 

especially sensitive to acidification include portions of 

the Northeast (particularly, the Adirondack and Catskill 

Mountains, portions of New England, 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 
604

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 
605

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 
606

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 
607

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 SOX

deposition very likely results in methylmercury 

accumulation in fish (Drevnick et al., 2007; Munthe et al, 

2007). The SO2 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
608

Ozone causes discernible injury to a wide array of 

vegetation (U.S. EPA, 2006; Fox and Mickler, 1996). In 

terms of forest productivity and ecosystem diversity, ozone 

may be the pollutant with the greatest potential for 

regional-scale forest impacts (U.S. EPA, 2006). Studies 

have demonstrated repeatedly that ozone concentrations 

commonly observed in polluted areas can have substantial 

impacts on plant function (De Steiguer et al., 1990; Pye, 

1988).

Assessing the impact of 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 ozone, scientists 

have developed ozone-exposure/tree-response functions by 

exposing tree seedlings to different ozone levels and 

measuring reductions in growth as “biomass loss.” 

Typically, seedlings are used because 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 
609

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 effects on seedlings compound to 

affect long-term forest health (Heck, 1997).

Urban ornamentals are an additional vegetation 

category likely to experience some degree of negative 

effects associated with exposure to ambient ozone levels. 

Because ozone causes visible foliar injury, the aesthetic 

value of 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 
610

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 
611

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 are unable to quantify any net climate-related 

disbenefit or benefit associated with the combined ozone 

and PM reductions in this rule.

Additionally, from analyses of the benefits of the 

Acid Rain Program, EPA has seen that substantial health and 

environmental benefits that are likely to occur for 

Canadians because 80 percent of the Canadian population 

lives within 40 miles of the US-Canada border.

TABLE IX–6.—UNQUANTIFIED AND NON-MONETIZED EFFECTS OF THE 

TRANSPORT RULE

Pollutant/ 

Effect Endpoint

PM: health a

Low birth weight

Pulmonary function

Chronic respiratory diseases other than 

chronic bronchitis

Non-asthma respiratory emergency room 

visits

UVb exposure (+/-)

c

PM: welfare Household soiling
612

Visibility in residential and non-class I 

areas

UVb exposure (+/-)

c

Global climate impacts c

Ozone: health

Chronic respiratory damage

Premature aging of the lungs

Non-asthma respiratory emergency room 

visits

Increased exposure to UVb (+/-)

c

Ozone: 

welfare

Yields for:

--Commercial forests

--Fruits and vegetables, and

--Other commercial and noncommercial crops

Damage to urban ornamental plants

Recreational demand from damaged forest 

aesthetics

Ecosystem functions

Increased exposure to UVb (+/-)

c

NO2: health

Respiratory hospital admissions

Respiratory emergency department visits

Asthma exacerbation

Acute respiratory symptoms

Premature mortality

Pulmonary function

NO2: welfare

Commercial fishing and forestry from acidic 

deposition

Commercial fishing, agriculture and 

forestry from nutrient deposition

Recreation in terrestrial and estuarine 

ecosystems from nutrient deposition

Other ecosystem services and existence 

values for currently healthy ecosystems

SO2: health

Respiratory hospital admissions

Asthma emergency room visits

Asthma exacerbation

Acute respiratory symptoms

Premature mortality

Pulmonary function

SO2: welfare

Commercial fishing and forestry from acidic 

deposition

Recreation in terrestrial and aquatic 

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 
613

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 NOX and SO2

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) 
614

that are simply redistributions of wealth. The social 

costs of this rule for the proposed remedy option are 

estimated to be approximately $2.0 billion in 2014 assuming 

a 3 percent discount rate. These 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, 
615

please refer to section XII.H (Statement of Energy Effects) 

later in this preamble.Ve2M

For this proposed rule, EPA analyzed the costs using 

the Integrated Planning Model (IPM). The IPM is a dynamic

linear programming model that can be used to examine the 

economic impacts of air pollution control policies for SO2

and NOX 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 
616

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 NOX and SO2

targeted by this rule. While all remedy options considered 

-- including the proposed remedy (State Budgets/Limited 

Trading) -- will lead to a modest increase in the relative 

cost-effectiveness of energy efficiency investments by 

internalizing environmental costs associated with these 

pollutants, EPA is interested in considering additional 

means by which energy efficiency can be encouraged through 
617

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 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 cost-effective 

energy efficient practices. Several federal programs 

authorized under the Act, including ENERGY STAR, are 

designed to address these barriers. 

By reducing the demand for electricity energy 

efficiency reduces the need for investments in EGU 
618

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 NOX and SO2

from power plants in affected states, a transport rule will 

lead to the internalization of costs associated with 

reducing the environmental effects of these pollutants. 

Since the economics of energy efficiency investments are 

directly related to power generation costs, this will 

improve the relative cost-effectiveness of these 

investments. Over time, this effect is expected to lead to 

increases in energy efficiency investments and associated 

benefits.

4. How have EPA and states previously integrated energy 
619

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 NOX 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 are realized) as are the emissions of 

non-capped pollutants from affected EGUs. In addition to 

these allowance-based programs, EPA has also established, 

through Guidance112, 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 

 

112 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
620

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, allowance-based 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 emission reductions requirements of the proposed 

rule are implemented through proposed FIPs. This means, 

among other things, that EPA allocates the emission 
621

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 
622

revisions to the PM2.5 and ozone NAAQS and intends to issue 

subsequent proposals to address the interstate transport 

requirements of section 110(a)(2)(D)(i)(I) with respect to 

those new NAAQS. The emissions reduction requirements 

identified in any such rules could be implemented through 

SIPs. The SIP process could give states significant 

flexibility in regards to allocation and auctioning of 

allowances. This flexibility could be used by states to 

support energy 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, 1993), this action is an “economically 

significant regulatory action” because it is likely to have 

an annual effect on the economy of $100 million or more or 

adversely affect in a material way the economy, a sector of 

the economy, productivity, competition, jobs, the 

environment, public health or safety, or State, local, or 

tribal governments or communities. 
623

Accordingly, EPA submitted this action to the Office 

of Management and Budget (OMB) for review under EO 12866 

and any changes made in response to OMB recommendations 

have been documented in the docket for this action. 

B. Paperwork Reduction 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 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 
624

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 SO2 and NOx 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, 
625

the Agency will publish a technical amendment to 40 CFR 

part 9 in the Federal Register to display the OMB control 

number for the approved information collection requirements 

contained in this final rule. 

C. Regulatory Flexibility Act

The 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.
626

(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. 

Table XII.C-1 — Potentially Regulated Categories and

Entitiesa

Category NAICS 

Codeb Examples of Potentially Regulated Entities

Industry 221112 Fossil fuel-fired electric utility steam 

generating units.

Federal 

Government

221112c Fossil fuel-fired electric utility steam 

generating units owned by the federal 

government.

State/Local

/

Tribal 

Government

221112c Fossil fuel-fired electric utility steam 

generating units owned by municipalities.

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 
627

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 
628

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 substantial number of 

small entities, EPA plans to take steps to conduct meetings 

with industry trade associations to discuss regulatory 

options and ensure that the burdens imposed on small 

entities are minimal. 
629

We continue to be interested in the potential impacts 

of the proposed rule on small entities and welcome comments 

on issues related to such impacts.

D. Unfunded Mandates Reform Act of 1995

Title II of the Unfunded Mandates Reform Act of 1995 

(UMRA), 2 U.S.C. 1531-1538, requires 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 
630

the final rule an explanation why that alternative was not 

adopted.

EPA examined the potential economic impacts on state 

and municipality-owned 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 
631

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 
632

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 
633

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 
634

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 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 
635

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 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 2014 as a result of higher demand for 

lower-sulfur coals. The EPA also projects that natural gas 
636

prices will increase by less than 1.7 percent in 2012 and 

that natural gas use for electricity generation will 

increase by less than 73 million mcf by 2014. The price 

increase is also within the range we regularly see in 

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 SO2 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 
637

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 No. 104-113, 

12(d) (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to 

do so would be inconsistent with applicable law or 

otherwise impractical. Voluntary consensus standards are 

technical standards (e.g., materials specifications, test 

methods, sampling procedures, and business practices) that 

are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency 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 cost-effective for the regulated 
638

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 LowIncome 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, 
639

disproportionately high and adverse human health or

environmental effects of their programs, policies, and 

activities on minority, low-income, and Tribal populations 

in the United States. 

1. Consideration of Environmental Justice Issues in the 

Rule Development Process

In the rulemaking process EPA 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 (PM2.5) nonattainment areas. This 

rule also has the potential to affect the cost structure of 

the utility industry and could lead to regional shifts in 

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 
640

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 webpage 

for the rule www.epa.gov/airtransport. This section 

summarizes the legal basis for this rule, and provides 

background information on how this rule fits into the 

larger regulatory strategy for controlling 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 
641

reducing their emissions. The court decision has led to 

significant uncertainty among affected sources as to what 

emission reductions will be required and among states and 

communities as to what air quality benefits will be 

achieved. By proposing this aggressive replacement rule 

that meets the legal requirements of the Clean Air Act 

(CAA) as interpreted by the Court in the North Carolina

decision promptly, EPA is both maximizing the likelihood 

that the 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 

emission reductions achieved under CAIR would be lost.

It is important to note that CAA § 110(a)(2)(d), which 

addresses transport of criteria pollutants between states 

and is the authority for this rule, is only one of many 

provisions of the CAA that provide EPA, states, and local 

governments with authorities to reduce exposure to ozone 

and PM2.5 in 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. 

Today’s proposed rule is one of a group of regulatory 

actions that EPA will take over the next several years to 
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respond to statutory and judicial mandates that will reduce 

exposure to ozone and PM2.5, as well as to other pollutants,

from power plants and other sources. To the extent that EPA 

has the legal authority to do so while fulfilling its 

obligations under the CAA and other relevant statues, we 

will also coordinate these utility-related air pollution 

rules with upcoming regulations for the power sector from 

EPA’s 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 today’s 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, PM2.5, 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 PM2.5 NAAQS as necessary; 
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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 
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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.

Emission reductions. This proposed rule will reduce 

exposure to PM2.5 and ozone pollution in most eastern states 

by reducing interstate transport of these pollutants and 

their chemical precursors (sulfur dioxide (SO2) and nitrogen 

oxides (NOx)). This rule has the effect of reducing

emissions of these pollutants that affect the most-
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contaminated areas (i.e. areas that are not meeting the 

1997 and 2006 ozone and PM2.5 National Ambient Air Quality 

Standards (NAAQS)). This rule separately 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 

emission reductions to protect maintenance areas as well as 

nonattainment areas reduces the likelihood that any areas 

close to the level of the standard will exceed the current

health-based standards in the future. 

Ozone and PM2.5 concentrations in both nonattainment 

and maintenance areas identified in this rule are the 

result of both local emissions and long-range transport of 

pollution. This rule requires upwind states to reduce or 

eliminate their significant contribution to nonattainment 

or maintenance problems in downwind states. Even when the 

significant contributions of upwind states are fully 

eliminated, additional emissions reductions within the 

nonattainment area and/or the downwind state will be needed 

for some areas to attain and maintain the NAAQS.

The proposed remedy option for this rule would use a 

limited emissions trading mechanism among power plants to 

achieve significant emission reductions in states covered 
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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.

This proposed rule uses EPA’s authority in CAA

§110(a)(2)(d) to require states to eliminate emissions from 

power plants in their state that contribute significantly 

to downwind PM2.5 or ozone nonattainment or maintenance 

areas. EPA’s proposed mechanism for achieving these 

emission reductions is to use a tightly constrained trading 

program that requires a strict emission ceiling in each 

state while allowing a limited ability to 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 emission reductions from another state in the 

region below that state’s budget or by using extra “banked” 
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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. 

PM2.5 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 emission 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 
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as long as another facility in the state had decreased 

theirs. By strictly setting state budgets to eliminate 

significant contributions to non-attainment and maintenance 

areas that EPA has identified in today’s action, by

limiting the amount of interstate trading possible and by 

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 

SO2 emissions from electric generating units (EGUs) will be 

approximately 6.4 million tons (60%) lower in 2014 than 

they were in 2005 (which is the year that the Clean Air 

Interstate Rule was finalized). Emissions would also 

decrease when compared to the base case (the base case 

estimates of SO2 emissions in 2014 in the absence of this 

proposed rule or the Clean Air Interstate Rule it is 

replacing). SO2 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 SO2 emissions (i.e., their emissions 
649

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 SO2 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 SO2

emissions would increase Texas’s contribution to an amount 

that would exceed the 0.15 μg/m3 threshold for annual PM2.5. 

For this reason, EPA requests comment on whether Texas 

should be included in the program as a group 2 state. For 

additional details, see section IV.D of this preamble.

With the exception noted above, EPA is not proposing 

for the SO2 portion of this rule to cover the states where 

SO2 emissions are projected to increase because EPA has not 

found, at this time, that they contribute significantly to 

nonattainment or interfere with maintenance of the PM2.5

NAAQS in downwind areas. EPA’s authority under 
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§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 SO2 reductions.

EPA’s emissions modeling data indicates that 

nationwide ozone season NOx 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 NOx 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 NOx reductions.

EPA anticipates that this proposed action will 

significantly reduce, but not eliminate, the number of 

nonattainment and maintenance areas for the 1997 ozone and 

PM2.5 and 2006 PM2.5 NAAQS. Table IX-1 lists the changes in 

number of nonattainment sites. Most of these sites are 
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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 emission reductions they need to 

address their own local nonattainment concerns. In 

addition, as stated above, elimination of these 

nonattainment areas may require both local and regional 

emission reductions and this proposed action seeks only to 

address the regional transport component.

As a result of these SO2 and NOx 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 

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 
652

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 

emission reductions far away can cause significant 

improvements in local air quality. 

The modeling suggests also that there may be some 

small increases in PM2.5 near locations in the western U.S. 

where SO2 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.
653

EPA’s air quality modeling also indicates that 

concentrations of ozone will decline in much of the eastern 

U.S. These reductions are largest along much of the Gulf 

Coast and in Florida and in a region 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 NOx SIP Call region. States in the SIP 

Call region were required to make significant reductions in 

NOx beginning in 2003 and these emission reductions are 

included in the baseline modeling for this proposed 

Transport Rule and therefore not captured as additional 

benefits of this rulemaking. 

As is common when modeling many NOx 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 NOx emissions in these local areas; 

they do not appear to represent a lack of NOx 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 
654

pollution in these areas. Due to the complex photochemistry 

of ozone production, NOx emissions lead to both the 

formation and destruction of ozone, depending on the 

relative quantities of NOx, volatile organic compounds, and 

ozone formation catalysts. In the 2014 base case, NOx

emissions from sources in a few locations act to “quench” 

(i.e., lower) ozone compared to ozone concentrations in 

surrounding areas. The application of NOx 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 NOx emission 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 PM2.5 and 

that the federal government and the states can and do use 

many different legal authorities to limit exposure to 

ozone. 
655

Health benefits. This rule reduces concentrations of 

PM2.5 and ozone pollution, exposure to which can cause, or 

contribute to, adverse health effects including premature 

mortality and many types of heart and lung diseases that 

affect many minority and low-income individuals, and Tribal 

communities. PM2.5 and ozone are particularly (but not 

exclusively) harmful to children, the elderly, and people 

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 PM-related annual 

benefits of the proposed remedy option include 

approximately 14,000 to 36,000 fewer premature mortalities, 

9,200 fewer cases of chronic bronchitis, 22,000 fewer nonfatal heart attacks, 11,000 fewer hospitalizations (for 
656

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. 
657

It should be noted that, as discussed in the RIA for 

this action, there are other benefits to the emission 

reductions discussed here, such as improved visibility and, 

indirectly, reduced mercury deposition. Additional benefits 

of reducing emissions of SO2 include reduced acidification 

of lakes and streams, and reduced mercury methylation; 

additional benefits of NOx 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 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 
658

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 SO2 and NOx reductions to help smooth 
659

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 
660

outside the region covered by this rule to experience 

slightly worse air quality as an indirect result of 

emission reductions required under this proposal. EPA 

requests comment on the impacts of this proposed action on 

low income, minority, and Tribal communities. EPA will 

further analyze environmental justice issues related to the 

impacts of the rule on those communities based both on 

additional data that may be developed and on comments on 

those issues prior to final action on this rule.
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List of Subjects

[add]

___________________________________

Dated:

___________________________________

Lisa P. Jackson,

Administrator.