Monday, 

August 2, 2010 

Part II 

Environmental 

Protection Agency 

40 CFR Parts 51, 52, 72, et al. 

Federal Implementation Plans To Reduce 

Interstate Transport of Fine Particulate 

Matter and Ozone; Proposed Rule 


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ENVIRONMENTAL PROTECTION 

AGENCY 

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

[EPA–HQ–OAR–2009–0491; FRL–9174–9] 

RIN 2060–AP50 

Federal Implementation Plans To 

Reduce Interstate Transport of Fine 

Particulate Matter and Ozone 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to limit the 

interstate transport of emissions of 

nitrogen oxides (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 the proposed FIPs do not 

fully address all significant transport, 

EPA is committed to assuring that any 

additional reductions needed are 

addressed quickly. EPA takes comments 

on ways this proposal could achieve 

additional NOX reductions and 

additional actions including other 

rulemakings that EPA could undertake 

to achieve any additional reductions 

needed. 

DATES: Comments. Comments must be 

received on or before October 1, 2010. 

Public Hearing: Three public hearings 

will be held before the end of the 

comment period. The dates, times and 

locations will be announced separately. 

Please refer to SUPPLEMENTARY

INFORMATION for additional information 

on the comment period and the public 

hearings. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2009–0491 by one of the following 

methods: 

• http://www.regulations.gov. Follow 

the online instructions for submitting 

comments. Attention Docket ID No. 

EPA–HQ–OAR–2009–0491. 

• E-mail: a-and-r-docket@epa.gov. 

Attention Docket ID No. EPA–HQ– 

OAR–2009–0491. 

• Fax: (202) 566–9744. Attention 

Docket ID No. EPA–HQ–OAR–2009– 

0491. 

• Mail: EPA Docket Center, EPA West 

(Air Docket), Attention Docket ID No. 

EPA–HQ–OAR–2009–0491, U.S. 

Environmental Protection Agency, 

Mailcode: 2822T, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

Please include 2 copies. In addition, 

please mail a copy of your comments on 

the information collection provisions to 

the Office of Information and Regulatory 

Affairs, Office of Management and 

Budget (OMB), Attn: Desk Officer for 

EPA, 725 17th Street, NW., Washington, 

DC 20503. 

• Hand Delivery: U.S. Environmental 

Protection Agency, EPA West (Air 

Docket), 1301 Constitution Avenue, 

Northwest, Room 3334, Washington, DC 

20004, Attention Docket ID No. EPA– 

HQ–OAR–2009–0491. Such deliveries 

are only accepted during the Docket’s 

normal hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions. Direct your comments to 

Docket ID No. EPA–HQ–OAR–2009– 

0491. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, avoid any form of 

encryption, and be free of any defects or 

viruses. For additional information 

about EPA’s public docket, visit the EPA 

Docket Center homepage at http:// 

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

Docket. All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

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

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket and 

Information Center, EPA/DC, EPA West 

Building, Room 3334, 1301 Constitution 

Ave., NW., Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Tim Smith, Air Quality Policy Division, 

Office of Air Quality Planning and 

Standards (C539–04), Environmental 

Protection Agency, Research Triangle 

Park, NC 27711; telephone number: 

(919) 541–4718; fax number: (919) 541– 

0824; e-mail address: 

smith.tim@epa.gov. For legal questions, 

please contact Ms. Sonja Rodman, U.S. 

EPA, Office of General Counsel, Mail 

Code 2344A, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460, 

telephone (202) 564–4079; e-mail 

address rodman.sonja@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. Preamble Glossary of Terms and 

Abbreviations 

The following are abbreviations of terms 

used in the preamble. 

ARP Acid Rain Program 

BART Best Available Retrofit Technology 

BACT Best Available Control Technology 

CAA or Act Clean Air Act 

CAIR Clean Air Interstate Rule 

CBI Confidential Business Information 

CFR Code of Federal Regulations 

EGU Electric Generating Unit 

FERC Federal Energy Regulatory 

Commission 

FGD Flue Gas Desulfurization 

FIP Federal Implementation Plan 

FR Federal Register 

EPA U.S. Environmental Protection Agency 

GHG Greenhouse Gas 

Hg Mercury 

IPM Integrated Planning Model 

lb/mmbtu Pounds Per Million British 

Thermal Unit 

μg/m3 Micrograms Per Cubic Meter 


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NAAQS National Ambient Air Quality 

Standards 

NOX Nitrogen Oxides 

NSPS New Source Performance Standard 

OTAG Ozone Transport Assessment Group 

PUC Public Utility Commission 

SNCR Selective Non-catalytic Reduction 

SCR Selective Catalytic Reduction 

SIP State Implementation Plan 

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. 

B. Where can I get a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, an electronic copy of this 

proposal will also be available on the 

World Wide Web. Following signature 

by the EPA Administrator, a copy of this 

action will be posted on the transport 

rule Web site http://www.epa.gov/ 

airtransport. 

C. What should I consider as I prepare 

my comments for EPA? 

1. Submitting CBI. Do not submit this 

information to EPA through http:// 

www.regulations.gov or e-mail. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD–ROM that 

you mail to EPA, mark the outside of the 

disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. Send or deliver 

information identified as CBI only to the 

following address: Roberto Morales, 

OAQPS Document Control Officer 

(C404–02), U.S. EPA, Research Triangle 

Park, NC 27711, Attention Docket ID 

No. EPA–HQ–OAR–2009–0491. 

2. Tips for preparing your comments. 

When submitting comments, remember 

to: 

• Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

• Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

• Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

D. How can I find information about the 

public hearings? 

The EPA will hold three public 

hearings on this proposal. The dates, 

times and locations of the pubic 

hearings will be announced separately. 

Oral testimony will be limited to 5 

minutes per commenter. The EPA 

encourages commenters to provide 

written versions of their oral testimonies 

either electronically or in paper copy. 

Verbatim transcripts and written 

statements will be included in the 

rulemaking docket. If you would like to 

present oral testimony at one of the 

hearings, please notify Ms. Pamela S. 

Long, Air Quality Policy Division 

(C504–03), U.S. EPA, Research Triangle 

Park, NC 27711, telephone number (919) 

541–0641; e-mail: long.pam@epa.gov. 

Persons interested in presenting oral 

testimony should notify Ms. Long at 

least 2 days in advance of the public 

hearings. For updates and additional 

information on the public hearings, 

please check EPA’s website for this 

rulemaking, http://www.epa.gov/ 

airtransport. The public hearings will 

provide interested parties the 

opportunity to present data, views, or 

arguments concerning the proposed 

rule. The EPA officials may ask 

clarifying questions during the oral 

presentations, but will not respond to 

the presentations or comments at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as any oral 

comments and supporting information 

presented at the public hearings. 

E. How is this Preamble Organized? 

I. Preamble Glossary of Terms and 

Abbreviations 

II. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this document 

and other related information? 

C. What should I consider as I prepare my 

comments for EPA? 

D. How can I find information about the 

hearings? 

E. How is the preamble organized? 

III. Summary of Proposed Rule and 

Background 

A. Summary of Proposed Rule 

B. Background 

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

this action? 

2. What air quality problems does this 

proposal address? 

3. Which NAAQS does this proposal 

address? 

4. EPA Transport Rulemaking History 

C. What are the goals of this proposed rule? 

1. Primary Goals 

2. Key Guiding Principles 

D. Why does this proposed rule focus on 

the eastern half of the United States? 

E. Anticipated Rules Affecting Power 

Sector 

IV. Defining ‘‘Significant Contribution’’ and 

‘‘Interference With Maintenance’’ 

A. Background 

1. Approach Used in 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? 


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1 In the context of the jurisdictions covered by 

this proposed rule, EPA uses the term ‘‘states’’ to 

include the District of Columbia. 

4. What are the estimated interstate 

contributions to annual 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 

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 Reductions Requirements 

Including Variability 

1. Variability 

2. State Budgets With Variability Limits 

3. Summary of Emissions Reductions 

Across All Covered States 

G. How the Proposed Approach Is 

Consistent With Judicial Opinions 

Interpreting Section 110(a)(2)(D)(i)(I) of 

the Clean Air Act 

H. Alternative Approaches Evaluated But 

Not Proposed 

V. Proposed Emissions Control Requirements 

A. Pollutants Included in This Proposal 

B. Source Categories 

1. Propose To Control Power Sector 

Emissions 

2. Other Source Categories Are Not 

Included 

C. Timing of Proposed Emissions 

Reductions Requirements 

1. Date for Prohibiting Emissions That 

Significantly Contribute or Interfere With 

Maintenance of the PM2.5 NAAQS 

2. Date for Prohibiting Emissions That 

Significantly Contribute or Interfere With 

Maintenance of the 1997 Ozone NAAQS 

3. Reductions Required by 2012 To Ensure 

That Significant Contribution and 

Interference With Maintenance Are 

Eliminated as Expeditiously as 

Practicable 

4. How Compliance Deadlines Address the 

Court’s Concern About Timing 

5. EPA Will Consider Additional 

Reductions in Pollution Transport To 

Assist in Meeting Any Revised or New 

NAAQS 

D. Implementing Emission Reduction 

Requirements 

1. Approach Taken in 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 

4. State-Level Emissions Projections 

F. Transition From the CAIR Cap-andTrade Programs to Proposed Programs 

1. Sunsetting of CAIR, CAIR SIPs, and 

CAIR FIPs 

2. Change in States Covered 

3. Applicability, CAIR Opt-Ins and 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. Permitting 

A. Title V Permitting 

B. New Source Review 

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? 

B. Incorporating End-Use Energy Efficiency 

Into the Transport Rule 

1. Options That Could Be Used To 

Incorporate Energy Efficiency Into 

Allowance Based Programs 

2. Why EPA did not propose these options? 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

1. Consideration of Environmental Justice 

Issues in the Rule Development Process 

2. Potential Environmental and Public 

Health Impacts to Vulnerable 

Populations 

3. Meaningful Public Participation 

4. Determination 

III. Summary of Proposed Rule and 

Background 

A. Summary of Proposed Rule 

CAA section 110(a)(2)(D)(i)(I) requires 

states to prohibit emissions that 

contribute significantly to 

nonattainment in, or interfere with 

maintenance by, any other state with 

respect to any primary or secondary 

NAAQS. In this notice, EPA proposes to 

find that emissions of 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 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 costeffective and flexible requirements for 

power plants. Each state will have the 

option of replacing these Federal rules 

with state rules to achieve the required 

amount of emissions reductions from 

sources selected by the state. 

With respect to the annual average 

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 interstate transport 


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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 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 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 interference with 

maintenance with the ozone standard as 

quickly as possible. (See full discussion 

in section IV.D.) 

This proposed rule is the first of 

several EPA rules to be issued over the 

next 2 years that will yield substantial 

health and environmental benefits for 

the public through regulation of power 

plants. Fossil-fuel-fired power plants 

contribute a large and substantial 

fraction of the emissions of several key 

air pollutants, and the agency has 

statutory or judicial obligations to make 

several regulatory determinations on 

power plant emissions. The 

Administrator in January established 

improved air quality as an Agency 

priority and announced plans to 

promote a cleaner and more efficient 

power sector and have strong but 

achievable reduction goals for 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. 

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 DC Circuit 

Court found CAIR and the CAIR FIPs 

unlawful. North Carolina v. EPA, 531 

F.3d 896 (DC Cir. 2008). The Court’s 

original decision vacated CAIR. Id. at 

929–30. However, the Court 

subsequently remanded CAIR to EPA 

without vacatur because it found that 

‘‘allowing CAIR to remain in effect until 

it is replaced by a rule consistent with 

our opinion would at least temporarily 

preserve the environmental values 

covered by CAIR.’’ North Carolina v. 

EPA, 550 F.3d 1176, 1178 (DC Cir. 

2008). The CAIR requirements are 

correctly in place and the CAIR’s 

regional control programs are operating 


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2For 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. 

3Consistent 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. 

while EPA develops replacement rules 

in response to the remand. 

As described more fully in the 

remainder of this preamble, the 

approaches used in this proposed rule 

to measure and address each state’s 

significant contribution to downwind 

nonattainment and interference with 

maintenance are guided by and 

consistent with the Court’s opinion in 

North Carolina v. EPA and address the 

flaws in CAIR identified by the Court 

therein. Among other things, the 

proposal relies on detailed, bottom-up 

scientific and technical analyses, 

introduces a state-specific methodology 

for identifying significant contribution 

to nonattainment and interference with 

maintenance, and proposes remedy 

options to ensure that all necessary 

reductions are achieved in the covered 

states. 

In this action, EPA proposes to both 

identify and address emissions within 

states in the eastern United States that 

significantly contribute to 

nonattainment or interfere with 

maintenance by other downwind states. 

As discussed in sections III and VII in 

this preamble and described in greater 

detail in two separate Federal Register 

notices published on April 25, 2005 (70 

FR 21147) and June 9, 2010 (75 FR 

32673), EPA has determined, or 

proposed to determine, that the 32 states 

covered by this proposal either have not 

submitted SIPs adequate to meet the 

requirements of 110(a)(2)(D)(i)(I) with 

respect to the 1997 and 2006 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 statespecific methodology to identify 

specific reductions that states in the 

eastern United States must make to 

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

prohibition on emissions that 

significantly contribute to 

nonattainment or interfere with 

maintenance in a downwind state. The 

proposed methodology uses statespecific inputs and focuses on the 

emissions reductions available in each 

individual state to address the Court’s 

concern that the approach used in CAIR 

(which identified a single level of 

emissions achievable by the application 

of highly cost effective controls in the 

region) was insufficiently state specific. 

The proposed methodology uses air 

quality analysis to determine whether a 

state’s contribution to downwind air 

quality problems is above specific 

thresholds. If a state’s contribution does 

not exceed those thresholds, its 

contribution is found to be insignificant 

and it is no longer considered in the 

analysis. If a state’s contribution 

exceeds those thresholds, EPA takes a 

second step that uses a multi-factor 

analysis that takes into account both air 

quality and cost considerations to 

identify the portion of a state’s 

contribution that is significant or that 

interferes with maintenance. Section 

110(a)(2)(D) requires states to eliminate 

the emissions that constitute this 

‘‘significant contribution’’ and 

‘‘interference with maintenance.’’ 

This proposed methodology for 

determining upwind state emission 

reduction responsibility is designed to 

be applicable to current and potential 

future ozone and 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 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 

season 3 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 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 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 


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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 statespecific budgets and allows intrastate 

and limited interstate trading. EPA is 

also taking comment on two alternative 

regulatory options. All options would 

achieve the emissions reductions 

necessary to address the emissions 

transport requirements in section 

110(a)(2)(D)(i)(I) of the CAA. 

The option EPA is proposing for the 

FIPs (‘‘State Budgets/Limited Trading’’) 

would use state-specific emissions 

budgets and allow for intrastate and 

limited interstate trading. This approach 

would assure environmental results 

while providing some limited flexibility 

to covered sources. The approach would 

also facilitate the transition from CAIR 

to the Transport Rule for implementing 

agencies and covered sources. 

The first alternative remedy option for 

which EPA requests comment would 

use state-specific emissions budgets and 

allow intrastate trading, but prohibit 

interstate trading. The second 

alternative remedy option, for which 

EPA also requests comment, would use 

state-specific budgets and emissions rate 

limits. See section V for further 

discussion of the remedy options. 

The proposed remedy option and the 

first alternative, both of which are capand-trade approaches, would use new 

allowance allocations developed on a 

different basis from CAIR. Allowance 

allocations, like the state budgets 

described previously, would be 

developed based on the methodology 

used by EPA to quantify each state’s 

significant contribution and interference 

with maintenance. See section IV for the 

proposed state budget approach and 

section V for proposed allowance 

allocation approaches. 

In this action, EPA proposes to 

require reductions in 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, 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 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. Sources will be 

required to comply by January 1, 2012 

and January 1, 2014 for the first and 

second phases, respectively. With 

respect to the 1997 ozone NAAQS, EPA 

proposes to require an initial phase of 

NOX reductions starting in 2012 to 

ensure that reductions are made as 

expeditiously as practicable. Sources 

will be required to comply by May 1, 

2012 and May 1, 2014 for the first and 

second phases, respectively. EPA has 

determined, that for many states, these 

reductions will be sufficient to 

eliminate their significant contribution 

with respect to the 1997 ozone NAAQS. 

EPA intends to issue a subsequent 

proposal that would require all 

significant contribution and interference 

with maintenance be eliminated by a 

future date for the 1997 ozone NAAQS. 

See Table III.A–1 for proposed lists of 

covered state. 

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

Covered for 

8-hour ozone 

Required to 

reduce SO2 and 

NOX

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 


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4With 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. 

TABLE III.A–1—LISTS OF COVERED STATES FOR PM2.5 AND 8-HOUR OZONE NAAQS—Continued 

State 

Covered for 

24-hour and/or 

annual PM2.5

Covered for 

8-hour ozone 

Required to 

reduce SO2 and 

NOX

Required to 

reduce ozone 

Season NOX

Georgia ............................................................................................................................................................ X X 

Illinois ............................................................................................................................................................... X X 

Indiana ............................................................................................................................................................. X X 

Iowa ................................................................................................................................................................. X ............................

Kansas ............................................................................................................................................................. X X 

Kentucky .......................................................................................................................................................... X X 

Louisiana .......................................................................................................................................................... X X 

Maryland .......................................................................................................................................................... X X 

Massachusetts ................................................................................................................................................. X ............................

Michigan ........................................................................................................................................................... X X 

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

Mississippi ........................................................................................................................................................ ............................ X 

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

Nebraska .......................................................................................................................................................... X ............................

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

New York ......................................................................................................................................................... X X 

North Carolina .................................................................................................................................................. X X 

Ohio ................................................................................................................................................................. X X 

Oklahoma ......................................................................................................................................................... ............................ X 

Pennsylvania .................................................................................................................................................... X X 

South Carolina ................................................................................................................................................. X X 

Tennessee ....................................................................................................................................................... X X 

Texas ............................................................................................................................................................... ............................ X 

Virginia ............................................................................................................................................................. X X 

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

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

Totals ........................................................................................................................................................ 28 26 

As discussed previously, EPA is 

proposing new 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. 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 

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 


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5Projected Transport Rule emissions result from 

individual stae budgets in the proposed approach 

and include some banking of allowances in 2012 

adn use of that bank in 2014. 

6EPA’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 IPM Documentation for further information on 

the base case modeling. 

contribution and interference with 

maintenance with respect to the 1997 

ozone NAAQS. While this proposal 

assures downwind states that they will 

receive relief from upwind reductions 

that will help them achieve the NAAQS, 

EPA is committed to fulfilling its 

obligation to assure the downwind 

states that they receive the full relief 

they are entitled to under section 

110(a)(2)(D). The Agency intends to 

quickly address any remaining 

significant contribution to 

nonattainment and interference with 

maintenance in a subsequent action that 

will also address a new more stringent 

ozone standard that is expected to be 

established by EPA later in 2010. 

Tables III.A–2 and III.A–3 show 

projected Transport Rule emissions 

reductions for EGUs in all states that 

EPA proposes to cover. 

TABLE III.A–2—PROJECTED SO2 AND NOX EGU EMISSIONS IN COVERED STATES WITH THE TRANSPORT RULE 5

COMPARED TO BASE CASE 6 WITHOUT TRANSPORT RULE OR CAIR 

[Million tons] 

2012 

Base case 

emissions 

2012 

Transport 

rule 

emissions 

2012 

Emissions 

reductions 

2014 

Base case 

emissions 

2014 

Transport 

rule 

emissions 

2014 

Emissions 

reductions 

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 

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. 

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 ................................

Ozone Season ...................

2.9 

1.0 

1.6 

0.7 

1.7 

0.8 

1.6 

0.7 

1.7 

0.8 

* Emissions totals include states covered by either the Transport Rule or CAIR. For 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). 


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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), enduse energy efficiency (section XI), and 

statutory and executive order reviews 

(section XII). 

Table III.A–5 shows the results of the 

cost and benefits analysis for the 

proposed and alternate remedies. 

Further discussion of these results is 

contained in preamble section XII-A and 

in the Regulatory Impacts Analysis. A 

listing of health and welfare effects is 

provided in RIA Table 1–6. Estimates 

here are subject to uncertainties 

discussed further in the body of the 

document. The social costs are the loss 

of household utility as measured in 

Hicksian equivalent variation. The 

capital costs spent for pollution controls 

installed for CAIR were not included in 

the annual social costs since the 

Transport Rule did not lead to their 

installation. Those CAIR-related capital 

investments are roughly estimated to 

have an annual social cost less than 

$1.15 to $ 1.29 billion (under the two 

discount rates.) 

Most of the estimated PM-related 

benefits in this rule accrue to 

populations exposed to higher levels of 

PM2.5. Of these estimated PM-related 

mortalities avoided, about 80 percent 

occur among populations initially 

exposed to annual mean PM2.5 level of 

10 μg/m3 and about 97 percent occur 

among those initially exposed to annual 

mean PM2.5 level of 7.5 μg/m3. These are 

the lowest air quality levels considered 

in the Laden et al. (2006) and Pope et 

al. (2002) studies, respectively. This fact 

is important, because as we estimate 

PM-related mortality among populations 

exposed to levels of PM2.5 that are 

successively lower, our confidence in 

the results diminishes. However, our 

analysis shows that the great majority of 

the impacts occur at higher exposures. 

TABLE III.A–5—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF VERSIONS OF THE PROPOSED REMEDY

OPTION IN 2014 a

[Billions of 2006$] 

Description Preferred remedy—State budgets/ 

limited trading Direct control Intrastate trading 

Social costs: 

3% discount rate .............................. $2.03 ..................................................... $2.68 ..................................................... $2.49. 

7% discount rate .............................. $2.23 ..................................................... $2.91 ..................................................... $2.70. 

Health-related benefits: b, c

3% discount rate .............................. $118 to $288 + B .................................. $117 to $286 + B .................................. $113 to $276 + B. 

7% discount rate .............................. $108 to $260 + B .................................. $108 to $262 + B .................................. $104 to $252 + B. 

Net benefits (benefits-costs): 

3% discount rate .............................. $116 to $286 ......................................... $115 to $283 ......................................... $110 to $273. 

7% discount rate .............................. $105 to $258 ......................................... $105 to $259 ......................................... $101 to $249. 

Notes: (a) All estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for the year 2014. For 

notational purposes, unquantified benefits are indicated with a ‘‘B’’ to represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits that we 

were able to quantify. (b) The reduction in premature mortalities account for over 90 percent of total monetized benefits. Benefit estimates are 

national. Valuation assumes discounting over the SAB-recommended 20-year segmented lag structure described in Chapter 5. Results reflect 3 

percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000; OMB, 2003). 

The estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon, discussed further in Chapter 5. Benefits are shown as a range from Pope et al. (2002) to Laden et al. (2006). Monetized benefits do not include unquantified benefits, such as other 

health effects, reduced sulfur deposition or visibility. These models assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle type. (c) Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all 

unquantified benefits and disbenefits. Potential benefit categories that have not been quantified and monetized are listed in RIA Table 1–4. 

B. Background 

1. What is the source of EPA’s authority 

for this action? 

The statutory authority for this action 

is provided by the CAA, as amended (42 

U.S.C. 7401 et seq.). Relevant portions 

of the CAA include, but are not 

necessarily limited to, sections 

110(a)(2)(D), 110(c)(1), and 301(a)(1). 

Section 110(a)(2)(D) of the CAA, often 

referred to as the ‘‘good neighbor’’ 

provision of the Act, requires states to 

prohibit certain emissions because of 

their impact on air quality in downwind 

states. Specifically, it requires all states, 

within 3 years of promulgation of a new 

or revised NAAQS, to submit SIPs that: 

(D) Contain adequate provisions— 

(i) Prohibiting, consistent with the 

provisions of this subchapter, any 

source or other type of emissions 

activity within the State from emitting 

any air pollutant in amounts which 

will— 

(I) Contribute significantly to 

nonattainment in, or interfere with 

maintenance by, any other State with 

respect to any such national primary or 

secondary ambient air quality standard, 

or (II) Interfere with measures required 

to be included in the applicable 

implementation plan for any other State 

under part C of this subchapter to 

prevent significant deterioration of air 

quality or to protect visibility. (ii) Insuring compliance with the 

applicable requirements of sections 

7426 and 7415 of this title (relating to 

interstate and international pollution 

abatement). 42 U.S.C. 7410(a)(2)(D). 

This proposal addresses the 

requirement in section 110(a)(2)(D)(i)(I) 

regarding the prohibition of emissions 

within a state that significantly 

contribute to nonattainment or interfere 

with maintenance of the NAAQS in any 

other state. As discussed in greater 

detail later, EPA has previously issued 

two rules interpreting and clarifying the 

requirements of section 

110(a)(2)(D)(i)(I). The NOX SIP Call, 

promulgated in 1998, was largely 

upheld by the U.S. Court of Appeals for 

the DC Circuit in Michigan v. EPA, 213 

F.3d 663 (DC Cir. 2000). The CAIR, 

promulgated in 2005, was remanded by 

the DC Circuit in North Carolina v. EPA, 

531 F.3d 896 (DC Cir. 2008), modified 

on reh’g, 550 F.3d. 1176 (DC Cir. 2008). 

These decisions provide additional 

guidance regarding the requirements of 

section 110(a)(2)(D)(i)(I) and are 

discussed later in this section. 

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

Administrator of EPA general authority 

to ‘‘prescribe such regulations as are 

necessary to carry out [her] functions 

under this chapter.’’ 42 U.S.C. 

7601(a)(1). Pursuant to this section, EPA 

has authority to clarify the applicability 

of CAA requirements. In this action, 


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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 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 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 deficiency prior to promulgation 

of the FIP. 

2. What air quality problems does this 

proposal address? 

a. Fine Particles 

Fine particles are associated with a 

number of serious health effects 

including premature mortality, 

aggravation of respiratory and 

cardiovascular disease (as indicated by 

increased hospital admissions, 

emergency room visits, health-related 

absences from school or work, and 

restricted activity days), lung disease, 

decreased lung function, asthma attacks, 

and certain cardiovascular problems. 

See EPA, Air Quality Criteria for 

Particulate Matter (EPA/600/P–99/ 

002bF, October 2004) at 9.2.2.3. See also 

integrated science assessment for the 

PM NAAQS review, December 2009, 

http://cfpub.epa.gov/ncea/cfm/ 

recordisplay.cfm?deid=216546. 

Individuals particularly sensitive to fine 

particle exposure include older adults, 

people with heart and lung disease, and 

children. This rule, and the NAAQS to 

which it is related, consider the effects 

of fine particles on vulnerable 

populations (see further discussion in 

section XII.G and section XII.J of this 

notice). More detailed information on 

health effects of fine particles can be 

found on EPA’s Web site at: http:// 

epa.gov/pm/standards.html. 

In addition to effects on public health, 

fine particles are linked to a number of 

public welfare effects. First, PM2.5 are 

the major cause of reduced visibility 

(haze) in parts of the United States, 

including many of our national parks 

and wilderness areas. For more 

information about visibility, visit EPA’s 

Web site at http://www.epagov/visibility. 

Second, particles can be carried over 

long distances by wind and then settle 

on ground or water. The effects of this 

settling include: Making lakes and 

streams acidic; changing the nutrient 

balance in coastal waters and large river 

basins; depleting the nutrients in soil; 

damaging sensitive forests and farm 

crops; and affecting the diversity of 

ecosystems. More information about 

these effects is available at EPA’s Web 

site at http://www.epa.gov/acidrain/ 

effects/index.html. Finally, particle 

pollution can stain and damage stone 

and other materials, including culturally 

important objects such as statues and 

monuments. 

In 1997, EPA revised the NAAQS for 

PM to add new annual average and 24- 

hour standards for fine particles, using 

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 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 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 


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program (under CAA Title IV) tracking 

system decreased from 10.2 million tons 

in 2005 to 7.6 million tons in 2008. 

Almost all of these emissions reductions 

were achieved in the areas of the eastern 

United States covered by the CAIR. See 

http://www.epa.gov/airmarkt/progress/ 

ARP_4.html. EPA believes that there 

would be substantially more 

nonattainment counties for both the 

annual and 24-hour standards if the 

CAIR were not in effect. 

As required by the CAA, and in 

response to litigation over the 2006 

standards, EPA is currently conducting 

a review of the 2006 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 October 2011. EPA is 

planning to propose the revised 

standards by February 2011. 

b. Ozone 

Short-term (1- to 3-hour) and 

prolonged (6- to 8-hour) exposures to 

ambient ozone have been linked to a 

number of adverse health effects. At 

sufficient concentrations, short-term 

exposure to ozone can irritate the 

respiratory system, causing coughing, 

throat irritation, and chest pain. Ozone 

can reduce lung function and make it 

more difficult to breathe deeply. 

Breathing may become more rapid and 

shallow than normal, thereby limiting a 

person’s normal activity. Ozone also can 

aggravate asthma, leading to more 

asthma attacks that may require a 

doctor’s attention and the use of 

additional medication. Increased 

hospital admissions and emergency 

room visits for respiratory problems 

have been associated with ambient 

ozone exposures. Longer-term ozone 

exposure can inflame and damage the 

lining of the lungs, which may lead to 

permanent changes in lung tissue and 

irreversible reductions in lung function. 

A lower quality of life may result if the 

inflammation occurs repeatedly over a 

long time period (such as months, years, 

or a lifetime). There is also recent 

epidemiological evidence indicating 

that there is a correlation between shortterm ozone exposure and premature 

mortality. 

People who are particularly 

susceptible to the effects of ozone 

include people with respiratory 

diseases, such as asthma. Those who are 

exposed to higher levels of ozone 

include adults and children who are 

active outdoors. This rule, and the 

NAAQS which it is related to, consider 

the effects of ozone on vulnerable 

populations (see further discussion in 

section XII.G and section XII.J of this 

notice). 

In addition to causing adverse health 

effects, ozone affects vegetation and 

ecosystems, leading to reductions in 

agricultural crop and commercial forest 

yields; reduced growth and survivability 

of tree seedlings; and increased plant 

susceptibility to disease, pests, and 

other environmental stresses (e.g., harsh 

weather). In long-lived species, these 

effects may become evident only after 

several years or even decades and have 

the potential for long-term adverse 

impacts on forest ecosystems. Ozone 

damage to the foliage of trees and other 

plants can also decrease the aesthetic 

value of ornamental species used in 

residential landscaping, as well as the 

natural beauty of our national parks and 

recreation areas. More detailed 

information on effects of ozone can be 

found at the following EPA Web site: 

http://www.epa.gov/ttn/naaqs/ 

standards/ozone/s_o3_index.html. 

In 1997, at the same time we revised 

the 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 highest 24-hour maximum 8-hour 

average ozone concentration may not 

exceed 0.08 ppm. In general, the 8-hour 

standards are more protective of public 

health and the environment and more 

stringent than the pre-existing 1-hour 

ozone standards. 

At the time EPA published the CAIR 

and the CAIR FIP rulemakings, wide 

geographic areas, including most of the 

nation’s major population centers, 

experienced ozone levels that violated 

the 1997 NAAQS of 8-hour ozone 0.08 

ppm (effectively 0.084 ppm as a result 

of rounding). These areas included 

much of the eastern part of the United 

States and large areas of California. The 

EPA published the 8-hour ozone 

attainment and nonattainment 

designations in the Federal Register on 

April 30, 2004 (69 FR 23858). These 

designations, based on ozone season 

monitoring data for the 2001–2003 time 

period, resulted in 112 areas designated 

as nonattainment. As of December 2009, 

significant emissions reductions have 

allowed 58 of the original 112 

nonattainment areas to be re-designated 

to attainment. In addition, a number of 

areas still designated as nonattainment 

ozone monitoring data for 2006–2008 

(most recent data available) show levels 

below the standard. EPA believes a 

number of factors contributed to 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 discussing the 

effect of the NOX SIP Call reductions 

can be found on EPA’s Web site at: 

http://www.epa.gov/airmarkets/ 

progress/progress-reports.html. 

Additional information on emissions 

and air quality trends are available in 

EPA’s 2007 and 2008 air quality trends 

reports, which are available at: http:// 

www.epa.gov/airtrends/. 

Second, mobile source emissions 

standards for onroad gasoline and 

vehicle emissions standards began to 

reduce mobile source emissions as the 

fleet began turning over vehicles to meet 

tightened 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 soon. Information on the 2008 

revisions to the ozone standard, and on 

all subsequent activity based on the 

reconsideration, is available at: http:// 

www.epa.gov/air/ozonepollution/ 

actions.html#sep09s. 

3. Which NAAQS does this proposal 

address? 

This proposed action addresses the 

requirements of CAA section 

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

(1) The 1997 annual 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 μg/3 standard for 

24-hour PM2.5 and a 65 μg/m3 standard 

for annual PM2.5. In 2006, the 24-hour 

PM2.5 standard was lowered to 35 μg/m3

and the 15 μg/m3 annual PM2.5 standard 

was left unchanged. 


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7 In addition, section 115 authorizes EPA to 

require a SIP revision in certain circumstances 

when one or more sources within a state ‘‘cause or 

contribute to air pollution which may reasonably be 

anticipated to endanger public health or welfare in 

a foreign country.’’ 

For this proposal, EPA fully addresses 

the requirements of CAA section 

110(a)(2)(D)(i)(I) for the annual PM2.5

standard of 15 μg/m3. For the 24-hour 

standard of 35 μg/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 

technical analyses and other work 

needed to address interstate transport 

for the reconsidered ozone standard as 

soon as possible. We intend to issue as 

soon as possible a proposal to address 

the transport requirements with respect 

to the reconsidered standard. 

4. EPA Transport Rulemaking History 

a. CAA Provisions 

For almost 40 years, Congress has 

focused major efforts on curbing 

ground-level ozone. In 1970, Congress 

amended the CAA to require, in Title I, 

that EPA issue and periodically review 

and, if necessary, revise NAAQS for 

ubiquitous air pollutants (sections 108 

and 109). Congress required the states to 

submit SIPs to attain and maintain those 

NAAQS, and Congress included, in 

section 110, a list of minimum 

requirements that SIPs must meet. 

Congress anticipated that areas would 

attain the NAAQS by 1975. 

In 1977, Congress amended the CAA 

by providing, among other things, 

additional time for areas that were not 

attaining the ozone NAAQS to do so, as 

well as by imposing specific SIP 

requirements for those nonattainment 

areas. These provisions first required 

the designation of areas as attainment, 

nonattainment, or unclassifiable, under 

section 107; and then required that SIPs 

for ozone nonattainment areas include 

the additional provisions set out in part 

D of Title I, as well as demonstrations 

of attainment of the ozone NAAQS by 

either 1982 or 1987 (section 172). 

In addition, the 1977 Amendments 

included two provisions focused on 

interstate transport of air pollutants: the 

predecessor to current section 

110(a)(2)(D), which requires SIPs for all 

areas to constrain emissions with 

certain adverse downwind effects; and 

section 126, which, in general, 

authorizes a downwind state to petition 

EPA to impose limits directly on 

upwind sources found to adversely 

affect that state. Section 

110(a)(2)(D)(i)(I), which is key to the 

present action, is described in more 

detail later. 

In 1990, Congress amended the CAA 

to better address, among other things, 

continued nonattainment of the 1-hour 

ozone NAAQS, the requirements that 

would apply if EPA revised the 1-hour 

standard, and transport of air pollutants 

across state boundaries (Pub. L. 101– 

549, Nov. 15, 1990, 104 Stat. 2399, 42 

U.S.C. 7401–7671q). 

As amended in 1990, the CAA further 

requires EPA to designate areas as 

attainment, nonattainment, and 

unclassifiable under a revised NAAQS 

(section 107(d)(1); section 6103, Pub. L. 

105–178). The CAA authorizes EPA to 

classify areas that are designated 

nonattainment under the new NAAQS 

and to establish for those areas 

attainment dates that are as expeditious 

as practicable, but not to exceed 10 

years from the date of designation 

(section 172(a)). 

All areas are required to submit SIPs 

within certain timeframes (section 

110(a)(1)), and those SIPs must include 

specified provisions, under section 

110(a)(2). In addition, SIPs for 

nonattainment areas are generally 

required to include additional specified 

control requirements, as well as controls 

providing for attainment of any revised 

NAAQS and periodic reductions 

providing ‘‘reasonable further progress’’ 

in the interim (section 172(c)). If states 

do not submit SIPs in a timely or 

approvable manner, EPA has the 

authority to make findings of failure to 

submit or impose FIPs on specific 

sources in the state that contribute to 

downwind nonattainment and 

interference with maintenance. 

Significant contribution and 

interference with maintenance are 

discussed in detail in section IV later. 

The 1990 Amendments reflect general 

awareness by Congress that ozone is a 

regional, and not merely a local, 

problem. Ozone and its precursors may 

be transported long distances across 

state lines, thereby exacerbating ozone 

problems downwind. Ozone transport is 

recognized as a major reason for the 

persistence of the ozone problem, 

notwithstanding the imposition of 

numerous controls, both Federal and 

State, across the country. 

The CAA further addresses interstate 

transport of pollution in section 126, 

which Congress revised slightly in 1990. 

Subsection (b) of that provision 

authorizes each state (or political 

subdivision) to petition EPA for a 

finding designed to protect that entity 

from upwind sources of air pollutants.7

In addition, the 1990 Amendments 

added section 184, which delineates a 

multi-state ozone transport region (OTR) 

in the Northeast, requires specific 

additional controls for all areas (not 

only nonattainment areas) in that 

region, and establishes the Ozone 

Transport Commission (OTC) for the 

purpose of recommending to EPA 

regionwide controls affecting all areas in 

that region. At the same time, Congress 

added section 176A, which authorized 

the formation of transport regions for 

other pollutants and in other parts of the 

country. 

In September 1994, the Northeast 

OTC states signed a Memorandum of 

Understanding (MOU) committing to 

reduce 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 emissions rate limits from certain 

coal plants under Title IV. 

Separate from activity in the OTC, 

EPA and the Environmental Council of 

the States (ECOS) formed the OTAG in 

1995. This workgroup brought together 

interested states and other stakeholders, 

including industry and environmental 

groups. Its primary objective was to 

assess the ozone transport problem and 

develop a strategy for reducing ozone 

pollution throughout the eastern half of 

the United States. 

Notwithstanding significant efforts, 

the states generally were not able to 

meet the November 15, 1994 statutory 

deadline for the attainment 

demonstration and rate of progress 

(ROP) SIP submissions required under 

section 182(c). The major reason for this 

failure was that at that time, states with 

downwind nonattainment areas were 

not able to address transport from 

upwind areas. As a result, EPA 

recognized that development of the 

necessary technical information, as well 

as the control measures necessary to 

achieve the large level of reductions 

likely to be required, had been 

particularly difficult for the states 

affected by ozone transport. 

Accordingly, as an administrative 

remedial matter, EPA established new 

timeframes for the required SIP 

submittals. To allow time for states to 

incorporate the results of the OTAG 


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8 Guidance for Implementing the 1-hour Ozone 

and Pre-Existing PM10 NAAQS, Memorandum from 

Richard D. Wilson, dated December 29, 1997. 

9The 8 states were Connecticut, Massachusetts, 

Maine, New Hampshire, New York, Pennsylvania, 

Rhode Island, and Vermont. 

10See Michigan v. EPA, 213 F.3d 663 (DC Cir. 

2000), cert. denied, 532 U.S. 904 (2001) (NOX SIP 

call) and Appalachian Power v. EPA, 251 F.3d 1026 

(DC Cir. 2001) (technical amendments). 

modeling into their local plans, EPA 

extended the submittal date to April 

1998.8 The OTAG’s air quality modeling 

and recommendations formed the basis 

for what became the 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 

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 cost-effective 

manner. Therefore, EPA believed that 

the OTAG recommendations for how to 

address ozone transport were valid for 

both NAAQS. 

The EPA published a supplemental 

notice of proposed rulemaking (SNPR) 

dated May 11, 1998 (63 FR 25902), 

which proposed a model 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 at levels allowed by the preexisting 1-hour ozone standards. The 1- 

hour primary standard was replaced by 

an 8-hour standard at a level of 0.08 

ppm, with a form based on the 3-year 

average of the annual fourth-highest 

daily maximum 8-hour average ozone 

concentration measured at each monitor 

within an area. The new primary 

standard provided increased protection 

to the public, especially children and 

other at-risk populations, against a wide 

range of ozone-induced health effects. 

The pre-existing 1-hour secondary 

ozone standard was replaced by an 8- 

hour standard identical to the new 

primary standard. The new secondary 

standard provided increased protection 

to the public welfare against ozoneinduced effects on vegetation. 

Section 126 Petitions. In a separate 

rulemaking, EPA proposed action on 

petitions submitted by 8 northeastern 

states 9 under section 126 of the CAA. 

Each petition specifically requested that 

EPA make a finding that 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 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 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 

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-andcomment rulemaking. The EPA believed 


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11U.S.EPA. September, 2009. The NOX Budget 

Trading Program: 2008 Environmental Results, p.9. 

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’’ (May–September). The 

EPA determined emissions reductions 

requirements for the covered states and 

source categories (see section IV.A for a 

description of the approach EPA used to 

determine emissions reductions 

requirements). The affected states were 

required to submit SIPs providing the 

specified amounts of emissions 

reductions. By eliminating these 

amounts of 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 (DC Circuit). In Michigan v. EPA, 

213 F.3d 663 (DC Cir., 2000), cert. 

denied, 532 U.S. 904 (2001), the Court 

upheld the rule in most respects. Of 

greatest relevance here, the Court 

upheld the essential features of EPA’s 

approach to identifying and eliminating 

states’’ 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 (DC 

Cir. 2000). 

The decision resolved only issues 

involving the 1-hour ozone NAAQS and 

did not resolve any issues involving the 

8-hour NAAQS, which provided 

another basis for the rule. See id. at 670– 

71. EPA ultimately stayed the 8-hour 

basis of the NOX SIP Call. See 65 FR 

56245. In addition, in a subsequent case 

that reviewed separate EPA rulemakings 

making technical corrections to the NOX

SIP Call, the DC Circuit remanded the 

case for a better explanation of EPA’s 

methodology for computing the growth 

component in the EGU heat input 

calculation. See Appalachian Power Co. 

v. EPA, 251 F.3d 1026 (DC Cir. 2001). 

More recently, the Court also rejected a 

challenge to a subsequent EPA rule 

withdrawing EPA’s findings of 

significant contribution for Georgia for 

the 1-hour ozone standard. See North 

Carolina v. EPA, 587 F.3d 422 (DC Cir. 

2009). 

(3) How the 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 Mid-Atlantic. 

The cap level was intended to protect 

public health and the environment and 

to sustain that protection into the future 

regardless of growth in the affected 

sector. Ozone season 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 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 

2008.11 Changes in ozone and nitrate 

concentrations due to the NBP have also 

contributed to improvements in 

ecosystems in the East. 

EPA stopped administering the NBP 

at the conclusion of 2008 control period 

activities. States still have the emissions 

reductions requirement and could use 

the CAIR 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 

generally required to include additional 

emissions controls providing for 

attainment of the NAAQS. 

As described previously, section 

110(a)(2)(D)(i)(I) provides a tool for 

addressing the problem of transported 

pollution that significantly contributes 

to downwind nonattainment and 

maintenance problems. Under section 

110(a)(2)(D), a SIP must contain 

adequate provisions prohibiting sources 

in the state from emitting air pollutants 

in amounts that would contribute 

significantly to nonattainment or 

interfere with maintenance in one or 

more downwind states. Section 

110(k)(5) authorizes EPA to find that a 

SIP is substantially inadequate to meet 

any CAA requirement. If EPA makes 

such a finding, it is to require the state 


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12The 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. 

13The term ‘‘transport’’ includes the transport of 

both PM2.5 and their precursor emissions and/or 

transport of both ozone and its precursor emissions. 

to submit, within a specified period, a 

SIP revision to correct the inadequacy 

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

authority to issue the 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 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 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 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 multistate 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 cost-effective way. 

The requirements in the CAIR were 

intended to address regional interstate 

transport of air pollution. EPA 

recognized, however, that additional 

local reductions might be necessary to 

bring some areas into attainment even 

after significantly contributing upwind 

emissions were eliminated. 70 FR 

25165–66, May 12, 2005. In addition, 

states that shared an interstate 

nonattainment area were expected to 

work together in developing the 

nonattainment SIP for that area, 

reducing emissions that contributed to 

local-scale interstate transport problems. 

CAIR FIPs. When EPA promulgated 

the final CAIR in May 2005, EPA also 

issued a national finding that states had 

failed to submit SIPs to address the 

requirements of CAA section 

110(a)(2)(D)(i) with respect to the 1997 

ozone and 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 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 DC 

Circuit. In North Carolina v. EPA, 531 


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F.3d 896, modified on reh’g 550 F.3d 

1176 (D.C. Cir. 2008), the Court granted 

several of the petitions for review and 

remanded the rule to EPA for further 

proceedings. In its July 2008 opinion, 

North Carolina, 531 F.3d 896, the Court 

upheld several challenged aspects of 

EPA’s approach, but also found fatal 

flaws in the rule—flaws it found 

significant enough to warrant vacatur of 

the CAIR and the associated FIPs in 

their entirety. In December 2008, 

however, the Court responded to 

petitions for rehearing and determined 

that ‘‘notwithstanding the relative flaws 

of CAIR, allowing the CAIR to remain in 

effect until it is replaced by a rule 

consistent with our opinion would at 

least temporarily preserve the 

environmental values covered by CAIR.’’ 

North Carolina, 550 F.3d at 1178. 

Accordingly, it decided to remand the 

rule without vacatur ‘‘so that EPA may 

remedy CAIR’s flaws in accordance with 

[the Court’s] July 11, 2008 opinion in 

this case.’’ Id. 

Although the entire rule was 

remanded, important parts of EPA’s 

rulemaking were upheld by the Court in 

its July 2008 ruling. The Court upheld 

key aspects of the air quality modeling 

portion of EPA’s significant contribution 

analysis. It upheld EPA’s decision to 

consider upwind states for inclusion in 

the CAIR only if those states contributed 

to projected nonattainment in 2010. See 

North Carolina, 531 F.3d at 913–914. 

The Court further upheld the 

contribution threshold used in the air 

quality modeling portion of the 

significant contribution analysis for 

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. 

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 

DC Circuit remanded the rule to EPA, it 

did so without vacatur allowing the rule 

to remain in effect while EPA addresses 

the remand. Thus, CAIR is continuing to 

help states address ozone and 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:// 

camddataandmaps.epa.gov/gdm/) and 

an assessment of emissions reduction 

data will be available at the end of each 

compliance period. 

C. What are the goals of this proposed 

rule? 

In developing this proposed rule, EPA 

was guided by a number of goals and 

guiding principles, as discussed in this 

section of the preamble. 

1. Primary Goals 

a. Respond to the Court Remand of the 

CAIR 

Most importantly, this proposal 

responds to the remand of the CAIR by 

the Court. As noted previously, the 

Court granted several petitions for 

review of the CAIR, finding fatal flaws 

with the rule; yet, it ultimately decided 

to remand the rule without vacatur to 

preserve the environmental benefits of 

the rule. North Carolina v. EPA, 531 

F.3d 896, modified on reh’g, 550 F.3d 

1176 (DC Cir. 2008). 

The action EPA is proposing would 

respond to the July and December 2008 

opinions of the DC Circuit and correct 

the flaws in the CAIR methodology that 

were identified by the Court. The action 

responds to the Court’s concerns in 

numerous ways. The methodology used 

to measure each state’s significant 

contribution emphasizes air quality 

considerations and uses state specific 

data and information. The methodology 

also gives independent meaning to the 

interfere with maintenance prong of 

section 110(a)(2)(D)(i)(I). The state 

budgets for 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 measurable 

progress towards eliminating emissions 

of SO2 and NOX that significantly 

contribute to or interfere with 

maintenance of the 1997 and 2006 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 


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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 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 June 9, 2010, EPA issued a 

notice making findings that states had 

not submitted SIPs under the 2006 PM2.5

NAAQS by the September 2009 

deadline. 75 FR 32673. These findings 

started a 2-year clock for the 

promulgation of a FIP by EPA unless, 

prior to that time, each state makes a 

submission to meet the requirements of 

110(a)(2)(D)(i)(I) and EPA approves the 

submission. This 2-year period will 

expire on July 9, 2012. This proposal is 

designed to provide FIPs for the 2006 

standards to ensure that the 

110(a)(2)(D)(i)(I) obligation is fully 

satisfied as it relates to those standards. 

EPA also notes that under FIPs, 

reduction requirements are immediately 

effective and thus FIPs provide for the 

most expeditious means to implement 

emissions reduction requirements. 

c. Address Transport Requirements 

With Respect to the 1997 Ozone 

Standards 

This proposed rule, in concert with 

other actions, largely eliminates upwind 

state emissions that contribute 

significantly to nonattainment in, or 

interfere with maintenance by, any 

other state with respect to the 1997 8- 

hour ozone NAAQS. EPA will issue a 

subsequent proposal for the 1997 8-hour 

ozone NAAQS to address fully the 

requirements of CAA Section 

110(a)(2)(D)(i)(I). EPA’s goal is to fully 

address transport requirements for the 

1997 ozone standards as soon as 

possible. 

d. Provide for a Smooth Transition From 

Existing Programs 

In addressing the Court remand in a 

way that satisfies the CAA transport 

requirements, EPA is also mindful of the 

need to ensure a smooth transition from 

the existing requirements. Substantial 

improvements in air quality have 

resulted from those requirements with 

associated health benefits. It is 

important not to lose those benefits as 

the new requirements move forward. It 

is also important to move quickly with 

those portions of the new requirements 

that provide the greatest benefits. 

2. Key Guiding Principles 

a. Appropriately Identify Necessary 

Upwind Reductions 

Emissions from upwind states can, 

alone or in combination with local 

emissions, result in air quality levels 

that exceed the NAAQS and jeopardize 

the health of residents in downwind 

communities. Each upwind state is 

required by the ‘‘good neighbor 

provision’’ to eliminate its individual 

significant contribution to downwind 

state nonattainment and to eliminate 

emissions that interfere with downwind 

states’’ maintenance of the air quality 

standards. The Act does not require 

upwind states to eliminate all emissions 

that affect downwind air quality or shift 

responsibility for attaining the NAAQS 

to the upwind states. Instead, the ‘‘good 

neighbor provision’’ requires each 

upwind state to, within 3 years of 

promulgation or revision of a NAAQS, 

submit a SIP to prohibit those emissions 

that significantly contribute to 

nonattainment or interfere with 

maintenance downwind. The 

prohibition on these emissions is 

intended to assist downwind states as 

they design strategies for ensuring that 

the NAAQS are attained and 

maintained. 

In practice, it is very complex for 

individual states to address the 

transport requirements. Generally for 

transport of ozone, and for transport of 

sulfate and nitrate fine particles, each 

downwind area is affected by emissions 

from multiple upwind states. In 

addition, in many cases states are 

simultaneously both upwind and 

downwind of one another. Further, only 

emissions that will significantly 

contribute to nonattainment or interfere 

with maintenance in another state are 

prohibited. Thus, an upwind state’s 

obligations are affected by the air 

quality downwind. Downwind air 

quality, in turn, is affected by both local 

emissions and the cumulative impact of 

emissions from all of the contributing 

upwind states. 

The problem of interstate transport is 

thus extremely complex and any 

remedy must acknowledge the inherent 

complexity of the problem. It is 

appropriate for EPA in developing such 

a remedy to be mindful of the 

interaction between upwind emissions 

controls and local emissions controls. 

The EPA continues to conclude, as it 

did in developing the CAIR, that it 

would be difficult if not impossible for 

many nonattainment areas to reach 

attainment through local measures 

alone, and EPA finds no information 

developed subsequent to development 

of CAIR to alter this conclusion. At the 

time of the proposed CAIR rule, EPA 

conducted a local measures analysis 

representing an ambitious set of 

measures and emissions reductions that 

may in fact be difficult to achieve in 

practice. (Ref: Section IX of Technical 

Support Document for the Interstate Air 

Quality Rule Air Quality Modeling 

Analyses, January 2004). This analysis 

was intended to provide illustrative 

examples of the nature of location 

measures and possible reductions. This 

analysis was not intended to precisely 

identify local emissions control 

measures that may be available in a 

particular area. The EPA continues to 

believe that a strategy based on adopting 

cost effective controls on sources of 

transported pollutants as a first step will 

produce a more reasonable, equitable, 

and optimal strategy than one beginning 

with local controls. The local measures 

analyses we conducted were not, 

however, intended to develop a specific 

or ‘‘optimal’’ regional and local 

attainment strategy for any given area. 

Rather, the analysis was intended to 

evaluate whether, in light of available 


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local measures, it is likely to be 

necessary to reduce significant regional 

transport from upwind states. EPA 

continues to believe that the two local 

measures analyses that were conducted 

for the CAIR strongly support the need 

for regional reductions of 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 

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 of the variability 

in the operation of the power grid, and 

that any requirements for broad 

reductions should be structured in a 

way that ensures a reliable power 

supply. 

e. Provide for Cost-Effectiveness 

EPA believes that is important to keep 

both cost-effectiveness and air quality 

objectives in mind in addressing the 

CAA transport requirements. 

f. Provide Incentives and Flexibility to 

the Regulated Community 

EPA seeks to provide approaches that 

provide regulated owners/operators of 

sources with the incentive to achieve all 

cost-effective reductions. EPA’s 

experience shows that providing this 

incentive, and the flexibility to seek 

alternatives to less cost-effective 

controls, provides for greater 

environmental protection at reduced 

cost. 

D. Why does this proposed rule focus on 

the eastern half of the United States? 

For this proposal, we identified a 37 

state region for the technical analysis, 

including all states east of the Rockies, 

from the Dakotas through Texas 

eastward. Western states also need to 

address the requirements of section 

110(a)(2)(D)(i)(I) of the CAA. However, 

the transport issues in the eastern 

United States are analytically distinct 

and this rule focuses only on that subset 

of the 110(a)(2)(D)(i)(I) issues. 

First, interstate transport of PM2.5 and 

ozone is a 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 serve to reinforce this point. 

Second, in developing the CAIR, EPA 

found that interstate transport 

(particularly for anthropogenic 

emissions) made much smaller 

contributions to exceedances of the 

1997 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 emissions 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 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 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 statutes, the Agency will also 

coordinate these utility-related air 

pollution rules with upcoming 

regulations for the power sector from 

EPA’s Office of Water (OW) and its 

Office of Resource Conservation and 

Recovery (ORCR). EPA expects that this 

comprehensive set of requirements will 

yield substantial health and 

environmental benefits for the public, 

benefits that can be achieved while 

maintaining a reliable and affordable 

supply of electric power across the 

economy. In developing and 

promulgating these rules, the Agency 

will be providing the power industry 

with a much clearer picture of what 

EPA will require of it in the next 

decade. In addition to promulgating the 

rules themselves, the Agency will 

engage with other federal, state and 

local authorities, as well as with 

stakeholders and the public at large, 

with the goal of fostering investments in 

compliance that represent the most 

efficient and forward-looking 

expenditure of investor, shareholder, 

and public funds, resulting, in turn, in 

the creation of a clean, efficient, and 

completely modern power sector. 

The major CAA rules that will drive 

these compliance investments are: (1) 

This transport rule; (2) potential future 

rules that may be needed to address 

transport under future revised ozone or 

fine particle health standards; (3) the 


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CAA Section 112(d) standards; (4) 

revisions to the NSPS for coal and oilfired electric utility steam generating 

units; and (5) BART requirements and 

other requirements that address 

visibility and regional haze. Within the 

planning and investment horizon for 

compliance with these rules, the EPA 

very likely will be compelled to respond 

a pending petition to set standards for 

the emissions of greenhouse gases from 

steam electric generating units under 

the NSPS program. Furthermore, as set 

forth in the recently promulgated 

reinterpretation of the Johnson Memo, 

beginning in 2011 new and modified 

sources of GHG emissions, including 

EGUs, will be subject to permits under 

the Prevention of Significant 

Deterioration program requiring them to 

adopt BACT for their GHGs. Finally, 

EPA will also pursue with other federal 

agencies, states, and other groups energy 

efficiency improvements in the use of 

electricity throughout the economy that 

will contribute to additional 

environmental and public health 

improvements that the Agency wants to 

provide while lowering the costs of 

realizing those improvements. 

A brief explanation of these major 

CAA rulemakings and activities follows. 

Transport Rule. This proposed 

transport rule includes emissions 

reductions requirements for EGUs to 

address interstate transport under the 

1997 ozone NAAQS, the 1997 PM2.5

NAAQS, and the 2006 PM2.5 NAAQS. 

After considering public comments on 

this proposal, EPA will endeavor to 

issue a final rule in spring 2011. 

Rules to Address Transport under 

Revised Air Quality Health Standards. 

EPA currently is reconsidering its 2008 

national ambient air quality standards 

for ozone, and is conducting a periodic 

review of the particulate matter 

NAAQS, including the fine particle 

standards. The Act requires EPA to 

ensure that primary standards are 

requisite to protect public health with 

an adequate margin of safety, and to set 

secondary standards requisite to protect 

public welfare. The Act requires EPA to 

review, and revise if appropriate, the 

primary and secondary NAAQS on a 

5-year schedule to ensure that air 

quality standards reflect the latest 

scientific information on health and 

welfare effects. When air quality 

standards are set or revised, the Act 

requires revision of SIPs to ensure that 

these standards to protect public health 

and welfare are met expeditiously and, 

in the case of the health-based 

standards, within timetables in the Act. 

If more protective NAAQS are 

promulgated, further emissions 

reductions would likely be needed in 

states where pollution levels exceed air 

quality standards, and in upwind states 

with emissions that significantly 

contribute to the air quality problems in 

another state. This may result in 

additional emission reduction 

requirements for facilities in the power 

sector, as well as for other sectors. The 

reconsideration of the March 2008 

ozone air quality standards will be 

completed soon, and the review of 

particulate matter air quality standards 

by October 2011. SIP deadlines and 

attainment deadlines would flow from 

those dates. 

EPA plans to make expeditious 

determinations of upwind state 

emissions reduction responsibilities for 

NAAQS for which interstate transport is 

an issue. This approach will lead to 

earlier emissions reductions to protect 

public health, as well as provide other 

benefits. In the North Carolina decision, 

the court made clear that downwind 

state nonattainment deadlines are 

legally relevant to the timing of 

reductions under section 110(a)(2)(D). 

Thus, expeditious determinations of 

upwind state responsibilities under 

section 110(a)(2)(D) can promote 

upwind reductions in time to help 

downwind states meet attainment 

deadlines, enable states and EPA to 

provide sources with earlier information 

on their emission reduction 

responsibilities, and maximize sources 

lead time to reduce emissions. 

If a more protective ozone NAAQS is 

issued in August, EPA would plan to 

propose an interstate pollution transport 

rule for that NAAQS in 2011. We would 

expect work on that proposal to proceed 

in parallel with efforts to finalize this 

Transport Rule for the 1997 and 2006 

NAAQS. A final rule to address 

interstate pollution transport for a 

reconsidered ozone NAAQS would be 

anticipated in 2012. In view of the 

implementation schedule for a 

reconsidered ozone NAAQS, 

compliance dates would be later than 

the compliance dates proposed for this 

Transport Rule, and would take into 

account attainment dates for that 

NAAQS and other factors such, as 

control cost and installation time. For 

any revised PM2.5 NAAQS, EPA plans to 

conduct a similarly expeditious analysis 

of interstate transport to support a 

determination as to whether or not 

further emissions reductions from the 

power sector are required under section 

110(a)(2)(D), in light of the emissions 

reductions required by other power 

sector rules. 

A revised SO2 NAAQS was issued on 

June 2 creating a new 1-hour SO2

NAAQS which, when implemented, 

will protect Americans from asthma and 

respiratory difficulties associated with 

short term exposures to SO2. Although 

EPA does not expect peak SO2 levels to 

be a long-range transport issue, power 

plants are among the sources that can 

contribute to peak SO2 levels and will 

likely be evaluated by states as they 

consider control measures to attain the 

new standards. Anticipated emissions 

reductions from power plants and other 

SO2 sources under other Clean Air Act 

(CAA or Act) requirements (e.g., 

transport rules, and MACT standards) 

are expected to play a significant role in 

attainment of the 1-hour SO2 NAAQS. 

Section 112(d) Standards for Utility 

Units. In 2008, the DC Circuit Court 

vacated the CAMR and the 112(n) 

Revision Rule, which removed coal- and 

oil-fired electric utility steam generating 

units from the section 112(c) list of 

sources subject to regulation. EPA is in 

the early stages of developing 

regulations under section 112 of the 

CAA that will require existing and new 

coal- and oil-fired utility units to meet 

emissions limits for mercury and other 

HAPs emitted from these sources. As 

required by section 112, EPA will issue 

a set of emissions standards. In part, the 

section 112(d) rule will require that all 

existing major sources achieve the 

emission limits for HAPs which will be 

at least as stringent as the average 

emissions reduction currently achieved 

by the best performing 12 percent of 

these units. Additionally, any new 

major source will be required to meet 

emission limits that are at least as 

stringent as what is currently achieved 

by the best-performing single source. 

Currently, the Agency is seeking data on 

five categories of HAP emissions: (1) 

Acid gases (e.g., hydrochloric acid, 

hydrogen fluoride, and hydrogen 

cyanide); (2) mercury; (3) Non-Hg 

metals (e.g., lead, cadmium, selenium, 

and arsenic); (4) dioxins/furans; and, (5) 

other organic hazardous air pollutants. 

EPA expects to receive the requested 

data, including stack testing results, by 

September 2010. EPA has agreed to sign 

the proposed rule by March 16, 2011, 

and sign the final rule no later than 

November 16, 2011. EPA may provide 

existing sources up to 3 years to comply 

with section 112(d) standards, and the 

CAA authorizes the permit authority to 

grant a 1 year extension of the 

compliance date on a case-by-case basis 

if such extension is necessary for the 

installation of controls. The CAA 

requires new sources to comply on the 

effective date of the final rule or at 

startup, whichever is later. If EPA were 

to provide 3 years for compliance with 

the section 112(d) standards, 


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compliance would generally be required 

by early 2015. 

In developing these rules, EPA will 

endeavor to proceed in a way that 

provides all stakeholders and other 

Federal, State and local decision-makers 

with ongoing, up-to-date information 

about the full suite of environmental 

responsibilities that the power sector 

must undertake. This, in turn, will 

enable power companies and others 

whose policies and decisions affect their 

investment choice to adopt compliance 

strategies that take full advantage of cocontrol opportunities and efficiencies 

and other approaches to maximizing the 

cost-effectiveness and leveraging 

benefits of their investments. 

New Source Performance Standards. 

NSPS are administered under section 

111 of the CAA. The standards for new, 

modified, and reconstructed steam 

EGUs are contained in 40 CFR part 60 

subpart Da, which was last amended in 

2006. The current structure of subpart 

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

emission/MWh) emission limits for NOX

and SO2 and optional output-based 

standards for particulate matter. EPA is 

currently re-evaluating the standards in 

Subpart Da to determine whether they 

reflect the degree of emission limitation 

achievable through the application of 

the best system of emission reduction, 

which the Administrator determines has 

been adequately demonstrated. EPA also 

has a pending voluntary remand to 

decide whether NSPS standards for this 

source category should include limits 

on GHG emissions. EPA is considering 

the timetable for these actions and 

decisions in light of legal obligations 

and policy considerations, including the 

desirability of the industry knowing its 

regulatory obligations to inform 

investment decisions. 

Regional Haze/BART. States are 

required to develop SIPs that address 

regional haze in scenic areas such as 

national parks and wilderness areas. 

EPA regulations for regional haze 

appear in Chapter 40 of the CFR in 

sections 51.308 and 51.309. One of the 

requirements of the regional haze SIPs 

is to provide for BART for large 

industrial sources including EGUs. The 

BART provisions affect EGUs put into 

operation between 1962 and 1977. 

Energy Efficiency. Policies that will 

promote efficient use of electric power 

can be an integral, highly cost-effective 

component of power companies’’ 

compliance strategies. Reducing 

demand for electricity can in itself 

achieve large emissions reductions and 

public health benefits, while enhancing 

the reliability of the grid. It can also 

lower the cost of emissions reductions 

for consumers of electricity and for the 

power industry, as investments are 

avoided in unnecessary infrastructure. 

EPA does not have sole responsibility 

for the development of energy policy to 

promote efficiency. To facilitate this 

component of the power sector’s 

compliance strategy, EPA intends to 

engage with other federal, state, and 

local agencies whose policies and 

actions can make it easier for power 

companies to adopt, or benefit from, 

energy efficiency investments in their 

compliance strategies. EPA will 

continue to use its authorities to 

advance energy efficiency by providing 

incentives for energy efficiency in our 

regulatory programs (e.g., output-based 

standards) and through our successful 

existing voluntary programs such as 

ENERGY STAR. The Department of 

Energy (DOE) also has considerable 

resources to encourage efficient use of 

electricity. Additional resources have 

been made available under the 

American Recovery and Reinvestment 

Act to both DOE and EPA to promote 

energy efficiency. State governments, 

both in their environmental programs 

and through their public service 

commissions, which regulate electric 

utility rates, can promote energy 

efficiency. Many state governments have 

been leaders in promoting efficient use 

of electricity through such mechanisms 

as energy efficiency standards and 

demand response, and EPA and DOE are 

assisting state governments in this 

effort. Local governments as well, 

through building codes, zoning, and 

other actions, can and do promote enduse energy efficiency. The Federal 

Energy Regulatory Commission (FERC) 

regulates wholesale electricity markets 

and sets mandatory reliability standards 

to assure a safe reliable power system. 

In carrying out this mission FERC 

recognizes that energy efficiency is a 

resource, to be considered along with 

other energy resources in reliability and 

economic planning. 

All of these entities will need to work 

in concert to achieve a truly efficient, 

reliable, cost-effective electric power 

system. EPA is committed to meeting 

this challenge. 

Non-Air Office Regulations. EPA is 

also working on three additional rules 

that will have potential impacts on the 

power sector. The Office of Solid Waste 

and Emergency Response is developing 

revised regulations for coal combustion 

residues, which are the combustion 

byproducts associated with the use of 

coal as a fuel. The Administrator signed 

the proposed rule on May 4, 2010. Over 

the next few years, EPA’s Office of 

Water plans to develop two rules 

affecting electric generating units; the 

precise timing of these rules is being 

determined. One will regulate cooling 

water intake structures. The other will 

revise the effluent guidelines for 

wastewater discharges from power 

plants. Each of these rules has cost 

implications to the power sector, and 

the Agency intends to coordinate these 

regulations with the upcoming air 

regulations. We intend to maximize 

reductions in pollution while 

maintaining cost-effective solutions. 

As a first step to carrying out its 

commitment to promote and facilitate 

the most cost-effective and forwardlooking compliance investments and 

strategies on the part of the power 

sector, EPA will conduct extensive 

outreach concerning the full range of the 

upcoming environmental 

responsibilities of the sector as it 

proposes the Transport Rule. Upon this 

proposal, the Agency will begin an 

outreach effort with the public, the 

regulated community, state air 

regulators, and others to (1) describe the 

Transport Rule proposal, and (2) 

provide information on the 2011 section 

112 standards for utility units and other 

upcoming EPA rulemakings affecting 

the power sector. The intent will be to 

inform all stakeholders of the industry’s 

obligations and opportunities for the 

industry to use investments in 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—who can 

play a significant role in promoting or 

requiring investment in energy 

efficiency. EPA intends to continue 

these efforts over time as more 

information becomes available in the 

development of the various rulemakings 

under development for the power 

sector. 

IV. Defining ‘‘Significant Contribution’’ 

and ‘‘Interference With Maintenance’’ 

This section describes EPA’s 

proposed approach to define emissions 

that significantly contribute to 

nonattainment or interfere with 

maintenance of the 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 


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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). 

15EPA 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) 

16Although 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. 

this proposed rule. Section IV.D 

provides a detailed description of EPA’s 

proposed approach to quantify 

emissions that significantly contribute 

and interfere with maintenance. Section 

IV.E includes proposed state emissions 

budgets before accounting for the 

inherent variability in power system 

operations. Section IV.F discusses the 

inherent variability in power system 

operations, proposes variability limits 

on the state budgets, and presents 

projected emissions reduction results. 

Section IV.G describes how the 

proposed approach is consistent with 

judicial opinions. Finally, section IV.H 

lists alternative approaches to defining 

significant contribution and interference 

with maintenance that EPA evaluated 

but is not proposing. 

A. Background 

1. Approach Used in 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 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) 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 thencurrent air quality of the area, the 

predicted future air quality (assuming 

implementation of required controls but 

not the transport requirements that were 

the subject of the 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 

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 cost-per-ton basis, 

may be considered to be highly cost 

effective’’ (63 FR 57377). Applying this 

cost factor on top of the air quality 

factor, EPA determined that emissions 

that both were from states that exceeded 


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17EPA did not address 24-hour PM2.5 NAAQS in 

CAIR, only the annual PM2.5 NAAQS. 

the air quality thresholds and could be 

eliminated through the application of 

highly cost-effective controls 

constituted a given state’s significant 

contribution. 

Choice of Highly Cost-Effective 

Standard. EPA chose the standard of 

‘‘highly cost-effective’’ in order to assure 

state flexibility in selecting control 

strategies to meet the emissions 

reduction requirements of the 

rulemaking. That is, the rulemaking 

required the states to achieve specified 

levels of emissions reductions—the 

levels achievable if states implemented 

the control strategies that EPA identified 

as highly cost-effective—but the 

rulemaking did not mandate those 

highly cost-effective control strategies, 

or any other control strategy. Indeed, in 

calculating the amount of the required 

emissions reductions by assuming the 

implementation of highly cost-effective 

control strategies, EPA assured that 

other control strategies—ones that were 

cost-effective, if not highly costeffective—remained available to the 

states. 

Determination of Highly Cost-Effective 

Amount. EPA determined the dollar 

amount considered to be highly costeffective by reference to the costeffectiveness of recently promulgated or 

proposed NOX controls. EPA 

determined that the average costeffectiveness 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 cost-effectiveness for 

summer ozone season emissions 

reductions as, at least directionally, the 

highly cost-effective amount. Identifying 

this amount on an ozone season basis 

was appropriate because the NOX SIP 

Call concerned the ozone standard, for 

which emissions reductions during only 

the summer ozone season are necessary. 

In determining the highly cost-effective 

amount, EPA analyzed costs on a 

regionwide basis, and assumed a cap 

and trade program for EGUs and large 

non-EGU boilers and turbines. 

Source Categories. EPA then 

determined that the source categories 

for which highly cost-effective controls 

were available included EGUs, large 

industrial boilers and turbines, and 

cement kilns. At the same time, EPA 

determined, for those source categories, 

the level of emissions reductions in 

each state that would result from the 

application of all controls that would be 

highly cost-effective and that would be 

feasible. The EPA considered other 

source categories, but found that highly 

cost-effective controls were not 

available for various reasons, including 

the size of the sources, the relatively 

small amount of emissions from the 

sources, or the control costs. 

Other Factors. EPA also relied on 

several other, secondary considerations 

to identify the required amount of 

emissions reductions. The first 

concerned the consistency of regional 

reductions with downwind attainment 

needs. The second general consideration 

was ‘‘the overall fairness of the control 

regimes’’ to which the downwind and 

upwind areas were subject. The third 

general consideration was ‘‘general cost 

considerations.’’ The EPA noted that ‘‘in 

general, areas that currently have, or 

that in the past have had, nonattainment 

problems * * * have already incurred 

ozone control costs.’’ The next set of 

controls available to these 

nonattainment areas would be more 

expensive than the controls available to 

the upwind areas. The EPA found that 

this cost scenario further confirmed the 

reasonableness of the upwind control 

obligations (63 FR 57379). 

In the 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 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 nonattainment areas, and the 

cost factor of highly cost-effective 

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 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 


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18The CAIR final preamble stated: ‘‘EPA has 

evaluated the attainment status of the downwind 

receptors in 2010 and 2015, and has determined 

that each upwind state’s 2010 and 2015 emissions 

reductions are necessary to the extent required by 

the rule because a downwind receptor linked to that 

upwind state will either (i) remain in 

nonattainment and continue to experience 

significant contribution to nonattainment from the 

upwind state’s emissions; or (ii) attain the relevant 

NAAQS but later revert to nonattainment due, for 

example, to continued growth of the emissions 

inventory.’’ 

that upwind 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 would result 

from application of highly cost-effective 

controls. In the CAIR, EPA determined 

the level of costs that would be highly 

cost-effective on a regional basis by 

reference to the cost effectiveness of 

other recent controls. EPA concluded 

that EGUs were the only source category 

for which highly cost-effective 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 meaning given to the term 

‘‘significant contribution.’’ That 

approach, which was found inconsistent 

with the requirements of 

110(a)(2)(D)(i)(I), is described later. 

EPA’s proposed new approach to 

interpreting ‘‘interfere with 

maintenance’’ is described in section 

IV.D, later. 

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-withmaintenance’’ issue, which is identifying the 

downwind areas whose maintenance of the 

NAAQS may suffer interference due to 

upwind emissions. The EPA has analyzed the 

‘‘interfere-with-maintenance’’ issue for the 

8-hour NAAQS by examining areas whose 

current air quality is monitored as attaining 

the 8-hour NAAQS [or which have no current 

air quality monitoring], but for which air 

quality modeling shows nonattainment in the 

year 2007. This result is projected to occur, 

notwithstanding the imposition of certain 

controls required under the CAA, because of 

projected increases in emissions due to 

growth in emissions generating activity. 

Under these circumstances, emissions from 

upwind areas may interfere with the 

downwind area’s ability to attain. 

Ascertaining the impact on the downwind 

area’s air quality of the upwind area’s 

emissions aids in determining whether the 

upwind emissions interfere with 

maintenance (62 FR 60326). 

In today’s action, EPA is taking the same 

positions with respect to the interfere-withmaintenance 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 

‘‘contribute significantly,’’ that is, through the 

same weight-of-evidence approach. 

CAIR: In the CAIR, EPA also 

interpreted ‘‘interfere with maintenance’’ 

in a limited way. EPA only considered 

whether upwind state emissions 

eventually posed a maintenance 

problem for areas that EPA projected to 

be in nonattainment in 2010 (the year 

that was the focus of the analysis of 

significant contribution to 

nonattainment). EPA did not examine 

whether areas in attainment in 2010 

might face a maintenance problem 

either in 2010 or thereafter, so no 

upwind state controls were considered 

to assist such areas with maintaining 

clean air. The CAIR preamble stated (70 

FR 25193, footnote 45), ‘‘we believe the 

‘interfere with maintenance’ prong may 

come into play only in circumstances 

where EPA or the state can reasonably 

determine or project, based on available 

data, that an [nonattainment] area in a 

downwind state will achieve 

attainment, but due to emissions growth 

or other relevant factors is likely to fall 

back into nonattainment.’’ 18

In responding to comments on the 

CAIR proposal, we also used this 

interpretation of the maintenance 

provision to help support the need for 

Phase II CAIR reductions. For ozone, we 

conducted an analysis that looked at (1) 

the amount by which receptor locations 

were projected to attain in 2015 and (2) 

the year-to-year variability in ozone 

levels due to weather and other factors 

based on a review of historical 

monitoring data. This analysis 

concluded that areas within 3–5 ppb of 

the standard, and sometimes greater 

(e.g., Fulton County, Atlanta) had 

historic variability as great as 8 ppb, and 

that this variability suggests strongly 

that upwind states could be interfering 

with maintenance even if modeling 

shows attainment by up to these 

amounts. For PM2.5, while we lacked 

historical data to support the same 

variability analysis, we characterized 

attaining the annual standard by 0.5 μg/ 

m3 as ‘‘attaining by a narrow margin’’ 

thus giving rise to maintenance 

concerns, and noted that in past (mobile 

source) rules we had indicated that 

attainment by a margin of 10 percent or 

less could be considered to raise 

maintenance concerns. 

2. Judicial Opinions 

a. Significant Contribution 

In North Carolina v. EPA, 531 F.3d. 

896 (DC Cir. 2008), the Court held that 

the approach EPA used in CAIR to 

measure each state’s significant 

contribution was insufficient. EPA, the 

Court concluded, had failed to 

‘‘measure[ ] the significant contribution 

from sources within an individual state 

to downwind nonattainment areas.’’ Id. 

at 907. The Court further reasoned that 

the lack of a state-specific significant 

contribution analysis made it 

impossible for EPA to show that the 


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trading programs and state budgets 

established to implement the trading 

programs, effectuated the section 

110(a)(2)(D)(i)(I) statutory mandate to 

eliminate emissions within the state that 

significantly contribute to 

nonattainment or interfere with 

maintenance in other states. 

Specifically, the court rejected the 

regional scope of EPA’s analysis. It 

reasoned that ‘‘because EPA evaluated 

whether its proposed emissions were 

‘highly cost effective’ at the regionwide 

level assuming a trading program, it 

never measured the ‘significant 

contribution’ from sources within an 

individual state to downwind 

nonattainment areas.’’ Id. at 907. In 

reaching this conclusion, however, the 

Court also recognized that aspects of 

EPA’s methodology for analyzing 

significant contribution had been 

upheld in Michigan v. EPA, 213 F.3d 

663 (DC Cir. 2000), and it left those 

holdings undisturbed. Specifically, the 

Court acknowledged its prior 

conclusion that ‘‘significance may 

include cost’’ North Carolina, 531 F.3d 

at 919 (citing Michigan 213 F.3d 677– 

79), and thus it is acceptable for EPA to 

use cost to ‘‘draw the ‘significant 

contribution’ line’’. Id. The Court also 

recognized that Michigan approved 

EPA’s decision to apply a uniform 

emissions control requirement to all 

upwind states despite different levels of 

contribution. See North Carolina, 531 

F.3d at 908. The Court thus concluded 

that while EPA must ‘‘measure each 

state’s ‘significant contribution’ to 

downwind nonattainment’’ that 

measurement need not ‘‘directly 

correlate with each state’s 

individualized air quality impact on 

downwind nonattainment relative to 

other upwind states.’’ Id. at 908. 

In North Carolina, the Court also 

upheld several aspects of the air quality 

modeling EPA used in the significant 

contribution analysis. It upheld EPA’s 

use of whole state modeling, see id. at 

923–26, and deferred to EPA’s selection 

of the 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. 

See North Carolina, 531 F.3d at 910. 

The Court rejected the approach used in 

CAIR reasoning that it ‘‘provides no 

protection for downwind areas that, 

despite EPA’s predictions, still find 

themselves struggling to meet NAAQS 

due to upwind interference in 2010.’’ Id. 

at 910–11. 

3. Overview of Proposed Approach 

In this section, EPA will explain how 

it proposes to identify which states are 

significantly contributing to downwind 

non-attainment and/or interfering with 

maintenance of the NAAQS at 

downwind sites and to quantify what 

that contribution is. 

In this action, EPA is proposing to use 

a two step approach to measuring each 

state’s significant contribution. The 

methodology used is based on the 

approach used in CAIR and the 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 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 from EGUs in each 

individual upwind state at the 

appropriate maximum cost threshold. 

These emissions reductions are the 

amount of the upwind state’s significant 

contribution. The cost thresholds used 

in this portion of the analysis, in 

contrast to the thresholds used in CAIR 

and the 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 it has been 

identified in this proposal) until they 

reach the higher cost threshold. The 

lower cost threshold applies to a state if 

the reduction in emissions at that 

threshold eliminates nonattainment and 

maintenance problems at all ‘‘linked’’ 

sites. 

EPA considers that the maintenance 

concept has two components: Year-toyear variability in emissions and air 

quality, and continued maintenance of 

the air quality standard over time. Both 

components of maintenance are 

addressed in this proposal. 

Step One: Air Quality Analysis 

In step one of this proposed approach, 

EPA analyzes emissions from 37 states 

to quantify the impact of those 

emissions on downwind nonattainment 

and maintenance sites in 2012 (see 

section IV.C for a detailed discussion of 

air quality modeling). To begin this 

analysis, EPA first identifies all 

monitors projected to be in 

nonattainment or, based on historic 

variability in air quality, projected to 

have maintenance problems in 2012. 

This baseline analysis takes into 

account emissions reductions associated 

with the implementation of all federal 

rules promulgated by December 2008 

and assumes that the CAIR is not in 

effect. This baseline presents a unique 

situation. EPA has been directed to 

replace the CAIR; yet the CAIR remains 

in place and has led to significant 

emissions reductions in many states. 

A key step in the process of 

developing a 110(a)(2)(D)(i)(I) rule 

involves analyzing existing (base case) 

emissions to determine which states 

significantly contribute to downwind 

nonattainment and maintenance areas. 

EPA cannot prejudge at this stage which 

states will be affected by the rule. For 

example, a state affected by CAIR may 

not be affected by the new rule and after 

the new rule goes into effect, the CAIR 

requirements will no longer apply. For 

a state covered by CAIR but not covered 

by the new rule, the CAIR requirements 

would not be replaced with new 

requirements, and therefore an increase 

in emissions relative to present levels 

could occur in that state. More 

fundamentally, the court has made clear 

that, due to legal flaws, the CAIR rule 

cannot remain in place and must be 

replaced. If EPA’s base case analysis 


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were to ignore this fact and assume that 

reductions from CAIR would continue 

indefinitely, areas that are in attainment 

solely due to controls required by CAIR 

would again face nonattainment 

problems because the existing 

protection from upwind pollution 

would not be replaced. For these 

reasons, EPA cannot assume in its base 

case analysis, that the reductions 

required by CAIR will continue to be 

achieved. 

Following this logic, the 2012 base 

case shows emissions higher than 

current levels in some states. Because 

EPA has been directed to replace CAIR, 

EPA believes that for many states, the 

absence of the CAIR 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 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 statespecific costs curves showing what level 

of emissions reductions could be 

achieved at different cost levels in 2012 

and 2014. EPA then uses a simplified air 

quality assessment tool to examine the 

impact of the reductions at specific cost 

levels on downwind nonattainment and 

maintenance sites. This approach allows 

EPA to identify specific cost breakpoints 

based on air quality considerations 

(such as the cost at which the air quality 

assessment analysis projects large 

numbers of downwind sites 

maintenance and nonattainment 

problems would be resolved) or cost 

criteria (such as being a cost where large 

emissions reductions occur because a 

particular technology is widely 

implemented at that cost). EPA then 

evaluated the reasonableness of the cost 

breakpoints using a number of criteria to 

determine which of the breakpoints 

appropriately represented a cost 

threshold with which to define 

significant contribution. 

These thresholds are then applied on 

a state-specific basis to quantify each 

individual state’s significant 

contribution. 

The remainder of this section 

provides further detail on the specific 

methodology developed by EPA and the 

application of this methodology to 

identify emissions that significantly 

contribute to or interfere with 

maintenance of the 1997 ozone NAAQS 

and the 1997 and 2006 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 

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 

section IV.C., and directly affects the 

proposed requirements of this rule. EPA 

also considered whether further 

reductions were necessary to ensure 

continued lack of interference with 

maintenance of the NAAQS over time. 

EPA concluded that in light of projected 

emission trends, and also considering 

the emissions reductions from this 

proposed rule, no further reductions are 

required solely for this purpose at PM 

and ozone receptors for which we are 

partially or fully determining significant 

contribution for the current NAAQS. 

(See discussion of emissions trends in 

Chapter 7 of TSD entitled ‘‘Emission 

Inventories,’’ included in the docket for 

this proposal.) 

1. Background 

a. For the CAIR, how did EPA determine 

which pollutants were necessary to 

control to address interstate transport 

for 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 


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fine particle problems (69 FR 4575–87). 

Key concepts and provisional 

conclusions drawn from this discussion 

were summarized as follows in the 

preamble to the final CAIR: 

(1) Fine particles (measured as 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’’ particles 

that are emitted directly to the 

atmosphere as particles, and 

‘‘secondary’’ particles that form in the 

atmosphere through chemical reactions 

from gaseous precursors. The major 

components of fine particles in the 

eastern U.S. can be grouped as follows: 

Carbonaceous material (including both 

primary and secondary organic carbon 

and black carbon); sulfates; nitrates; 

ammonium; and crustal material, which 

includes suspended dust as well as 

some other directly emitted materials. 

The major gaseous precursors of 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.’’ 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 

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 classes of compounds 

that possess a wide range of chemical 

properties and atmospheric lifetimes, 

which help determine their relative 

importance in forming ozone. Sources of 

VOCs include man-made sources such 

as motor vehicles, chemical plants, 

refineries, and many consumer 

products, but also natural emissions 

from vegetation. Nitrogen oxides 

contributing to ozone formation are 

emitted by motor vehicles, power 

plants, and other combustion sources, 

with lesser amounts from natural 

processes including lightning and soils. 

Key aspects of current and projected 

inventories for NOX and VOC are 

summarized in section IV of the 

proposal notice and EPA Web sites (e.g., 

http://www.gov/ttn/chief.) The relative 

importance of NOX and VOC in ozone 

formation and control varies with localand time-specific 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-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 largescale stagnation, which promote the 

build-up of direct emissions and 

pollutants formed through atmospheric 

reactions over large regions. 

Authoritative assessments of ozone 

control approaches have concluded that, 

for reducing regional scale ozone 

transport, a 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., 1,000s of kilometers) 

over much of the eastern U.S., with 

elevated concentrations occurring in 

rural as well as metropolitan areas. 

While substantial progress has been 

made in reducing ozone in many urban 

areas, regional scale ozone transport is 

still an important component of high 

ozone concentrations during the 

extended summer ozone season. A 

series of more recent progress reports 

discussing the effect of the NOX SIP Call 

reductions can be found on EPA’s Web 

site at: http://www.epa.gov/airmarkets/ 

progress/progress-reports.html. 

In the notice of proposed rulemaking 

for CAIR, EPA noted that we continue 

to rely on the assessment of ozone 


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19For 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 standards 

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 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 Web site at: http:// 

www.epa.gov/ttn/ecas/regdata/RIAs/ 

452_R_08_003.pdf. 

For addressing interstate ozone 

transport in the CAIR, EPA addressed 

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 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 

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

interpretation of this provision is that 

the emphasized terms make clear that 

the upwind state’s emissions must be 

controlled as long as they contribute 

significantly to a single nonattainment 

area. 

As discussed in section II of the 

preamble to the final CAIR, EPA’s 

approach to evaluating a state’s impact 

on downwind nonattainment 

considered the entirety of the state’s 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 state-level 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 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 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 area. 

The EPA’s first step in evaluating the 

results of these methodologies was to 

remove from consideration those states 

whose upwind contributions were very 

low. Specifically, EPA considered an 

upwind state not to contribute 

significantly to a downwind 

nonattainment area if the state’s 

maximum contribution to the area was 

either (1) less than 2 ppb; or (2) less than 

one percent of total nonattainment in 

the downwind area; as indicated by 

either of the two modeling techniques. 

If the upwind state’s impact exceeded 

these thresholds, then EPA conducted a 

further evaluation to determine if the 

impact was high enough to meet the air 

quality portion of the ‘‘contribute 

significantly’’ standard. In doing so, EPA 

organized the outputs of the two 

modeling techniques into a set of 

‘‘metrics.’’ The metrics reflect three key 

contribution factors: 

• The magnitude of the contribution 

(actual amount of ozone contributed by 

emissions in the upwind state to 

nonattainment in the downwind area); 

• The frequency of the contribution 

(how often contributions above certain 

thresholds occur); and 

• The relative amount of the 

contribution ( the total ozone 


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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 

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

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. 

A second reason that low threshold 

values are warranted, as EPA discussed 

in the notices for the CAIR, is that there 

are adverse health impacts associated 

with ambient PM2.5 and ozone even at 

low levels. See relevant portions of the 

CAIR proposal notice (63 FR 4583–84) 

and the CAIR final rule notice (70 FR 

25189–25192). 

For annual 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 μg/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. 

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 NAAQS. For 

example, if EPA were to 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. 

EPA seeks comment on the pollutants 

and air quality thresholds used for 

identifying states to be included under 

the proposed rule. In particular, EPA 

requests comment on alternatives to the 

1 percent threshold. In addition, EPA 

requests comment on whether EPA 

should use the same rounding 


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

20Comprehensive Air Quality Model with 

Extensions Version 5 User’s Guide. Environ 

International Corporation. Novato, CA. March 2009. 

21The 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. 

22Arunachalam, 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. 

23Pouliot, G., Pierce., T. ‘‘A Tale of Two Models: 

A comparison of the Biogenic Emission Inventory 

System (BEIS) and Model of Emissions of Gases and 

convention that was used in the final 

CAIR for the 15 μg/m3 annual PM2.5

standard, or whether commenters agree 

with EPA’s approach that does not use 

this rounding convention. To identify 

the potential effect of alternative 

thresholds for the annual PM2.5

standard, see Table IV.C–13 (showing 

state specific contributions to areas with 

annual PM2.5 nonattainment and 

maintenance issues) and Table IV.C–16 

(showing state specific contributions to 

areas with 24-hour PM2.5 nonattainment 

and maintenance issues). 

C. Air Quality Modeling Approach and 

Results 

1. What air quality modeling platform 

did EPA use? 

a. Introduction 

In this section, we describe the air 

quality modeling performed to support 

the proposed rule. We used air quality 

modeling to (1) identify locations where 

we expect there to be nonattainment or 

maintenance problems for annual 

average 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 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 the 

Comprehensive Air Quality Model with 

Extensions (CAMx) version 5 20 to 

simulate ozone and PM2.5

concentrations for the 2005 base year 

and the 2012 and 2014 future year 

scenarios. In contrast, for the CAIR EPA 

used two air quality models, CAMx 

version 3.1 for modeling ozone and the 

Community Multiscale Air Quality 

Model (CMAQ) version 4.3 for modeling 

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. The use of 

one model for both pollutants, as we 

have done for this proposal, provides a 

more scientifically integrated ‘‘one 

atmosphere’’ approach versus using 

different models for ozone and 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 km.21 The modeling region (i.e., 

modeling domain) extends from Texas 

northward to North Dakota and 

eastward to the East Coast and includes 

37 states and the District of Columbia. 

A map of the air quality modeling 

domain is provided in the AQMTSD. 

Both CAMx and CMAQ contain 

certain source apportionment tools that 

are designed to quantify the 

contribution of emissions from various 

sources and areas to ozone and PM2.5

component species in other downwind 

locations. The CAMx model was chosen 

for use in this proposal because the 

source apportionment tools in this 

model have had extensive use and 

evaluation by states and industry. Also, 

the source apportionment tools in 

CAMx received favorable comments in 

a recent peer review.22

The 2005-based air quality modeling 

platform used for the proposal includes 

2005 base year emissions and 2005 

meteorology for modeling ozone and 

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 

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 component 

species using other data sources, to 

provide the modeling species needed by 

CAMx. Elevated point sources were 

identified for simulating releases of 

emissions from those sources in layers 

2 and higher in CAMx. In addition to 

the anthropogenic emission sources 

described previously, hourly, gridded 

biogenic emissions were estimated for 

individual modeling days using the 

BEIS model version 3.14.23 24 The same 


erowe on DSK5CLS3C1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45239 

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. 

25The oil and gas exploration inventory was 

provided by the Western Regional Air Partnership. 

biogenic emissions data were used in all 

scenarios modeled. 

(1) Development of 2005 Base Year 

Emissions 

Emissions inventory inputs 

representing the year 2005 were 

developed to provide a base year for 

forecasting future air quality, described 

in section IV.C.2. The 2005 National 

Emission Inventory (NEI), version 2 

from October 6, 2008, was the starting 

point for the U.S. inventories used for 

the 2005 air quality modeling. This 

inventory includes 2005-specific data 

for point and mobile sources, while 

most nonpoint data were carried 

forward from version 3 of the 2002 NEI. 

In addition, a 2006 Canadian inventory 

and a 1999 Mexican inventory were 

used for the portions of Canada and 

Mexico within the modeling domains. 

Additional details on these inventories 

and the augmentation described here are 

available from the Emissions Inventory 

Technical Support Document (EITSD) 

for the Transport Rule. 

The onroad and nonroad emissions 

were primarily based on the National 

Mobile Inventory Model (NMIM) 

monthly, county, process level 

emissions from the 2005 NEI v2. The 

2005 onroad mobile emissions were 

augmented for onroad gasoline 

emissions sources with emissions based 

on a draft version of the Motor Vehicle 

Emissions Simulator (MOVES) for 

carbon monoxide (CO), 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. 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 to create state-specific 

profiles to allocate from annual to 

monthly values and from daily to hourly 

values. Only the 2005 data were used to 

create state-specific factors for 

allocation from month to day, which is 

intended to preserve an appropriate 

level of daily temporal variability 

needed for this type of modeling. 

Other significant augmentations were 

also made to the 2005 NEI and include 

the following. The nonpoint inventory 

was augmented with the oil and gas 

exploration inventory 25 which includes 

emissions in several states within the 

eastern U.S. 12 km modeling domain 

and additional states within the national 

36 km modeling domain. The 

commercial marine category 3 (C3) 

vessel emissions were augmented with 

gridded 2005 emissions from the 

previous modeling efforts for the rule 

called ‘‘Control of Emissions from New 

Marine Compression-Ignition Engines at 

or Above 30 Liters per Cylinder.’’ The 

2005 point source daily wildfire and 

prescribed burning emissions were 

replaced with average-year countybased inventories. Additionally, the 

inventories were processed to provide 

the hourly, gridded, model-species 

needed by CAMx. 

Tables IV.C–1 and IV.C–2 provide 

summaries of 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. 

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 


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

TABLE IV.C–1—2005 BASE CASE SO2 EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued 

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total 

Kentucky .................................................. 502,731 25,811 34,229 6,942 2,711 364 572,787 

Louisiana .................................................. 109,851 165,737 2,378 73,233 2,399 892 354,489 

Maine ....................................................... 3,887 18,519 9,969 3,725 834 150 37,084 

Maryland .................................................. 283,205 34,988 40,864 17,819 2,966 32 379,874 

Massachusetts ......................................... 85,768 19,620 25,261 25,335 2,168 93 158,245 

Michigan ................................................... 349,877 76,510 42,066 14,533 7,204 91 490,280 

Minnesota ................................................. 101,666 25,169 14,747 10,410 2,558 631 155,181 

Mississippi ................................................ 74,117 29,892 6,796 6,003 2,158 1,051 120,016 

Missouri .................................................... 284,384 78,307 44,573 10,464 4,251 186 422,165 

Nebraska .................................................. 74,955 6,429 29,575 9,199 1,326 105 121,589 

New Hampshire ....................................... 51,445 3,245 7,408 805 630 38 63,571 

New Jersey .............................................. 57,044 7,640 10,726 23,484 2,486 61 101,441 

New York ................................................. 180,847 58,562 125,158 20,908 5,628 113 391,216 

North Carolina .......................................... 512,231 66,150 22,020 42,743 5,341 696 649,181 

North Dakota ............................................ 137,371 9,458 6,455 5,986 443 66 159,779 

Ohio .......................................................... 1,116,084 118,468 19,810 15,615 6,293 22 1,276,292 

Oklahoma ................................................. 110,081 40,482 7,542 5,015 2,699 469 166,288 

Pennsylvania ............................................ 1,002,202 85,411 68,349 11,972 5,363 32 1,173,328 

Rhode Island ............................................ 176 2,743 3,365 2,494 208 1 8,987 

South Carolina ......................................... 218,782 31,495 30,016 20,477 2,976 646 304,393 

South Dakota ........................................... 12,215 1,698 10,347 3,412 511 498 28,682 

Tennessee ............................................... 266,148 78,206 32,714 6,288 4,834 277 388,468 

Texas ....................................................... 534,949 223,625 109,215 52,749 13,470 1,178 935,187 

Vermont .................................................... 9 902 5,385 385 305 49 7,036 

Virginia ..................................................... 220,248 69,440 32,923 18,420 3,829 399 345,259 

West Virginia ............................................ 469,456 48,314 14,589 2,133 1,095 215 535,802 

Wisconsin ................................................. 180,200 66,807 6,369 7,129 3,110 70 263,685 

Grand total ........................................ 10,019,774 1,953,745 1,117,009 596,847 123,547 19,345 13,380,267 

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 

Oklahoma ................................................. 86,204 73,465 94,574 55,424 117,240 1,709 ....................

Pennsylvania ............................................ 176,870 89,208 53,435 118,774 266,649 117 705,053 

Rhode Island ............................................ 545 2,164 2,964 7,798 13,456 4 26,930 

South Carolina ......................................... 53,823 29,069 20,281 68,146 128,765 2,357 302,441 

South Dakota ........................................... 15,650 5,035 5,766 30,324 24,850 1,817 83,442 

Tennessee ............................................... 102,934 60,353 18,676 82,331 207,410 1,012 472,717 

Texas ....................................................... 176,170 292,806 274,338 377,246 615,715 4,890 1,741,166 

Vermont .................................................... 297 799 3,438 3,951 13,316 179 21,980 

Virginia ..................................................... 62,512 60,101 53,605 91,298 194,173 1,456 463,145 

West Virginia ............................................ 159,804 36,913 14,519 32,739 50,040 785 294,801 


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

TABLE IV.C–2—2005 BASE CASE NOX EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued 

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total 

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

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

(2) Development of Future Year 

Emissions 

The future base case scenarios 

represent predicted emissions in the 

absence of any further controls beyond 

those federal measures already 

promulgated. For EGUs, all state and 

other programs available at the time of 

modeling have been included. For 

mobile sources, all national measures 

available at the time of modeling have 

been included. For nonEGU point and 

nonpoint stationary sources, any local 

control programs that may be necessary 

for areas to attain the annual 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 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 

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

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

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

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

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

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

Maine ....................................................... 15,759 18,519 9,950 3,926 156 150 48,460 

Maryland .................................................. 49,078 34,988 40,854 17,112 608 32 142,672 

Massachusetts ......................................... 16,299 19,622 25,242 29,825 575 93 91,657 

Michigan ................................................... 287,807 76,458 42,066 7,636 1,074 91 415,132 

Minnesota ................................................. 53,596 25,100 14,733 1,342 596 631 95,997 

Mississippi ................................................ 46,432 24,426 6,788 2,094 375 1,051 81,166 

Missouri .................................................... 445,643 78,310 44,550 1,307 765 186 570,761 

Nebraska .................................................. 120,790 6,430 29,571 817 209 105 157,921 

New Hampshire ....................................... 7,290 3,245 7,396 72 142 38 18,183 

New Jersey .............................................. 37,746 6,747 10,715 25,286 772 61 81,327 

New York ................................................. 144,074 58,566 125,187 12,336 1,541 113 341,818 

North Carolina .......................................... 126,620 66,128 22,000 48,861 935 696 265,240 

North Dakota ............................................ 77,383 9,458 6,451 288 76 66 93,722 

Ohio .......................................................... 946,667 105,406 19,810 3,456 1,131 22 1,076,493 

Oklahoma ................................................. 156,032 36,912 7,536 341 502 469 201,791 

Pennsylvania ............................................ 966,136 79,142 68,330 4,938 1,135 32 1,119,712 

Rhode Island ............................................ 0 2,743 3,364 2,879 82 1 9,069 

South Carolina ......................................... 149,515 31,452 30,005 22,697 532 646 234,846 

South Dakota ........................................... 13,453 1,698 10,342 65 91 498 26,147 

Tennessee ............................................... 596,987 77,595 32,701 828 795 277 709,182 

Texas ....................................................... 327,873 162,915 109,199 37,109 2,409 1,178 640,682 

Vermont .................................................... 0 902 5,381 6 94 49 6,432 

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

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

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

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

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 


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

TABLE IV.C–4—2012 BASE CASE NOX EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued 

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total 

Delaware .................................................. 4,639 5,567 3,248 15,511 10,700 23 39,687 

District of Columbia .................................. 2 501 1,739 2,704 4,857 0 9,802 

Florida ...................................................... 195,673 55,017 29,475 282,147 275,603 25,600 863,515 

Georgia .................................................... 78,011 53,317 38,825 76,901 158,771 7,955 413,780 

Illinois ....................................................... 77,920 92,440 47,564 167,046 157,915 71 542,957 

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

Iowa .......................................................... 66,316 39,301 15,064 72,031 58,920 90 251,721 

Kansas ..................................................... 70,823 70,751 42,249 66,897 43,914 378 295,012 

Kentucky .................................................. 149,179 34,875 17,446 72,289 71,284 1,326 346,399 

Louisiana .................................................. 44,773 161,724 27,525 285,562 64,074 3,254 586,912 

Maine ....................................................... 3,139 18,309 7,295 13,354 21,896 566 64,559 

Maryland .................................................. 17,376 24,624 21,647 53,580 64,368 137 181,731 

Massachusetts ......................................... 6,312 18,447 34,245 75,149 57,417 341 191,911 

Michigan ................................................... 96,874 93,953 43,392 80,900 163,505 330 478,955 

Minnesota ................................................. 51,285 64,250 56,581 92,080 86,198 2,300 352,694 

Mississippi ................................................ 37,517 52,454 12,151 64,138 52,709 3,833 222,801 

Missouri .................................................... 77,571 38,610 32,731 96,197 108,298 678 354,085 

Nebraska .................................................. 52,820 12,159 13,788 81,177 33,907 381 194,233 

New Hampshire ....................................... 2,514 3,243 11,153 7,308 19,710 137 44,067 

New Jersey .............................................. 15,987 18,996 26,320 81,906 76,979 223 220,410 

New York ................................................. 25,755 55,167 87,776 100,212 154,260 412 423,582 

North Carolina .......................................... 61,643 44,514 18,715 133,476 126,081 11,424 395,854 

North Dakota ............................................ 59,547 7,544 10,018 46,649 12,111 240 136,110 

Ohio .......................................................... 159,627 69,075 41,378 133,650 149,134 81 552,945 

Oklahoma ................................................. 86,858 71,808 94,528 43,057 71,207 1,709 369,167 

Pennsylvania ............................................ 193,032 85,168 53,289 92,594 142,217 117 566,418 

Rhode Island ............................................ 221 2,168 2,959 7,468 8,120 4 20,940 

South Carolina ......................................... 47,762 28,953 20,273 63,564 75,994 2,357 238,903 

South Dakota ........................................... 15,493 5,035 5,733 24,117 14,957 1,817 67,151 

Tennessee ............................................... 68,425 59,594 18,573 65,209 126,353 1,012 339,166 

Texas ....................................................... 159,738 287,831 274,203 313,204 303,453 4,890 1,343,319 

Vermont .................................................... 0 800 3,406 3,077 10,328 179 17,790 

Virginia ..................................................... 36,036 60,101 53,496 79,717 111,583 1,456 342,389 

West Virginia ............................................ 102,725 35,698 14,473 26,040 27,694 785 207,415 

Wisconsin ................................................. 49,351 40,694 21,979 58,951 86,315 256 257,546 

Grand Total ....................................... 2,485,856 1,904,481 1,299,224 3,075,459 3,232,168 80,932 12,078,120 

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 

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 


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TABLE IV.C–5—2014 BASE CASE SO2 EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued 

State EGU NonEGU Nonpoint Nonroad Onroad Fires Total 

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

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

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

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

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

Vermont .................................................... 0 903 5,380 7 101 49 6,439 

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

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

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

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

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 

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

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

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

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

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

Maine ....................................................... 2,535 18,316 7,257 13,169 18,061 566 59,903 

Maryland .................................................. 19,990 24,687 21,626 52,501 53,040 137 171,980 

Massachusetts ......................................... 6,619 18,527 34,207 75,654 46,748 341 182,095 

Michigan ................................................... 97,455 94,079 43,360 73,939 135,806 330 444,969 

Minnesota ................................................. 51,859 64,372 56,545 84,040 71,161 2,300 330,278 

Mississippi ................................................ 37,142 52,440 12,133 58,559 42,525 3,833 206,633 

Missouri .................................................... 82,979 38,744 32,677 88,233 90,001 678 333,312 

Nebraska .................................................. 52,970 12,173 13,779 75,252 27,856 381 182,410 

New Hampshire ....................................... 2,515 3,255 11,129 6,587 16,260 137 39,884 

New Jersey .............................................. 16,268 19,089 26,298 78,875 63,254 223 204,007 

New York ................................................. 28,350 55,359 87,826 92,841 129,376 412 394,165 

North Carolina .......................................... 61,747 44,573 18,669 133,455 104,150 11,424 374,018 

North Dakota ............................................ 59,556 7,549 3,969 42,972 9,925 240 130,252 

Ohio .......................................................... 164,945 69,157 41,352 120,900 122,426 81 518,861 

Oklahoma ................................................. 81,122 72,525 94,513 39,539 58,382 1,709 347,790 

Pennsylvania ............................................ 196,151 84,111 53,246 83,885 118,122 117 535,631 

Rhode Island ............................................ 281 2,186 2,957 7,384 6,772 4 19,585 

South Carolina ......................................... 47,512 28,969 20,271 62,400 62,996 2,357 224,505 

South Dakota ........................................... 15,514 5,039 5,157 22,021 12,254 1,817 62,368 

Tennessee ............................................... 68,779 59,694 18,542 59,145 104,711 1,012 311,882 

Texas ....................................................... 166,177 282,509 274,163 289,605 241,009 4,890 1,258,354 

Vermont .................................................... 0 803 3,397 2,771 8,563 179 15,713 

Virginia ..................................................... 32,115 60,216 53,464 75,461 92,291 1,456 315,002 

West Virginia ............................................ 100,103 35,700 14,459 23,798 22,863 785 197,708 

Wisconsin ................................................. 53,774 40,729 21,974 53,848 71,163 256 241,743 

Grand total ........................................ 2,468,057 1,900,624 1,298,473 2,884,338 2,656,134 80,932 11,288,558 

Development of Future-Year Emissions 

Inventories for Electric Generating Units 

Future year 2012 and 2014 base case 

EGU emissions used for the air quality 

modeling runs that predicted ozone and 

PM2.5 were obtained from version 3.02 

EISA of the IPM (http://www.epa.gov/ 

airmarkt/progsregs/epa-ipm/ 

index.html). The IPM is a multiregional, 

dynamic, deterministic linear 

programming model of the U.S. electric 

power sector; version 3.02 EISA features 

an updated Title IV 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 IPM 

Documentation. Also note that as 

explained in section IV.A.3, the baseline 

used in this analysis assumes no CAIR. 

If EPA’s base case analysis were to 


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

26 Grell, G., J. Dudhia, and D. Stauffer, 1994: A 

Description of the Fifth-Generation Penn State/ 

NCAR Mesoscale Model (MM5), NCAR/TN– 

398+STR., 138 pp, National Center for Atmospheric 

Research, Boulder CO. 

assume that reductions from CAIR 

would continue indefinitely, areas that 

are in attainment solely due to controls 

required by CAIR would again face 

nonattainment problems because the 

existing protection from upwind 

pollution would not be replaced. As 

explained in that section, EPA believes 

that this is the most appropriate 

baseline to use for purposes of 

determining whether an upwind state 

has an impact on a downwind 

monitoring site in violation of section 

110(a)(2)(D). 

Development of Future-Year Emissions 

Inventories for Mobile Inventories 

Mobile source inventories of onroad 

and nonroad mobile emissions were 

created for 2012 and 2015 using a 

combination of the NMIM and draft 

MOVES models. Mobile source 

emissions were further interpolated 

between 2012 and 2015 to estimate 2014 

emissions. Emissions for these years 

reflect onroad mobile control programs 

including the Light-Duty Vehicle Tier 2 

Rule, the Onroad Heavy-Duty Rule, and 

the Mobile Source Air Toxics (MSAT) 

final rule. Nonroad mobile emissions 

reductions for these years include 

reductions to locomotives, various 

nonroad engines including diesel 

engines and various marine engine 

types, fuel sulfur content, and 

evaporative emissions standards. A 

more comprehensive list of control 

programs included for mobile sources is 

available in the EITSD. 

The onroad emissions were primarily 

based on the NMIM monthly, county, 

process level emissions. For both 2012 

and 2015, emissions from onroad 

gasoline sources were augmented with 

emissions based on the same 

preliminary version of MOVES as was 

used for 2005. MOVES-based emissions 

were computed for CO, NOX, VOC, 

PM2.5, and PM10. The same MOVESbased 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 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. 

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 animal 

operations were projected based on 

animal population data from the 

Department of Agriculture and EPA. 

Residential wood combustion was 

projected by replacement of obsolete 

woodstoves with new woodstoves and a 

1 percent annual increase in fireplaces. 

Landfill emissions were projected using 

MACT controls. All other nonpoint 

sources were held constant between 

2005 and the future years. 

(3) Preparation of Emissions for AQ 

Modeling 

The annual and summer day 

emissions inventory files were 

processed through the Sparse Matrix 

Operator Kernel Emissions (SMOKE) 

Modeling System version 2.6 to produce 

the gridded model-ready emissions for 

input to CAMx. Emissions processing 

using SMOKE was performed to create 

the hourly, gridded data of CAMx 

species required for air quality modeling 

for all sectors, including biogenic 

emissions. Additional information on 

the development of the emissions data 

sets for modeling is provided in the 

EITSD. Details about preparation of 

emissions for contribution modeling are 

described in the Transport Rule AQ 

Modeling TSD. 

c. Preparation of Meteorological and 

Other Air Quality Modeling Inputs 

The gridded meteorological input data 

for the entire year of 2005 were derived 

from simulations of the Pennsylvania 

State University/National Center for 

Atmospheric Research Mesoscale 

Model. This model, commonly referred 

to as MM5, is a limited-area, 

nonhydrostatic, terrain-following 

system that solves for the full set of 

physical and thermodynamic equations 

which govern atmospheric motions.26

The meteorological outputs from MM5 

were processed to create model-ready 

inputs for CMAQ using the MM5-toCAMx preprocessor (ref CAMx user’s 

guide). 

The 2005 MM5 meteorological 

predictions for selected variables were 

compared to measurements as part of 

several performance evaluations of the 

predicted data. The evaluation approach 

included a combination of qualitative 

and quantitative analyses to assess the 

adequacy of the MM5 simulated fields. 

The qualitative aspects involved 

comparisons of the model-estimated 

synoptic patterns against observed 

patterns from historical weather chart 

archives. Additionally, the evaluations 

compared spatial patterns of monthly 

average rainfall and monthly maximum 

planetary boundary layer (PBL) heights. 

The operational evaluation included 


erowe on DSK5CLS3C1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45245 

27Baker K. and P. Dolwick. Meteorological 

Modeling Performance Evaluation for the Annual 

2005 Eastern U.S. 12-km Domain Simulation, 

USEPA/OAQPS, February 2, 2009. 

28Baker K. and P. Dolwick. Meteorological 

Modeling Performance Evaluation for the Annual 

2005 Western U.S. 12-km Domain Simulation, 

USEPA/OAQPS, February 2, 2009. 

29Baker K. and P. Dolwick. Meteorological 

Modeling Performance Evaluation for the Annual 

2005 Continental U.S. 36-km Domain Simulation, 

USEPA/OAQPS, February 2, 2009. 

30 Yantosca, B., 2006. GEOS–CHEMv7–04–11 

User’s Guide, Atmospheric Chemistry Modeling 

Group, Harvard University, Cambridge, MA, March 

05, 2006. 

31Henze, D.K., J.H. Seinfeld, N.L. Ng, J.H. Kroll, 

T-M. Fu, D.J. Jacob, C.L. Heald, 2008. Global 

modeling of secondary organic aerosol formation 

from aromatic hydrocarbons: high-vs. low-yield 

pathways. Atmos. Chem. Phys., 8, 2405–2420. 

32 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. 

33Clean Air Status and Trends Network 

(CASTNET) 2005 Annual Report. EPA Office of Air 

and Radiation, Clean Air Markets Division. 

Washington, DC. December 2006. 

statistical comparisons of model/ 

observed pairs (e.g., mean normalized 

bias, mean normalized error, index of 

agreement, root mean square errors, etc.) 

for multiple meteorological parameters. 

For this portion of the evaluation, five 

meteorological parameters were 

investigated: Temperature, humidity, 

shortwave downward radiation, wind 

speed, and wind direction. The three 

individual MM5 evaluations are 

described elsewhere.27 28 29 It was 

ultimately determined that the bias and 

error values associated with the 2005 

meteorological data were generally 

within the range of past meteorological 

modeling results that have been used for 

air quality applications. Additional 

details on the meteorological inputs can 

be found in the AQMTSD. 

As noted previously, the CAMx 

simulations for this proposal were 

performed using a spatial resolution of 

12 x 12 km. The concentrations of 

pollutants transported into this eastern 

U.S. modeling region were obtained 

from air quality model simulations 

performed at coarser 36 x 36 km 

resolution for a modeling domain 

covering the lower 48 states and 

portions of northern Mexico and 

southern Canada. The 12 x 12 km model 

simulations were also initialized with 

air quality predictions from the coarse 

scale modeling. Pollutant 

concentrations at the boundaries of the 

coarse scale modeling domain were 

obtained from a three-dimensional 

global atmospheric chemistry model, 

the GEOSChem 30 model (standard 

version 7–04–11 31). The global 

GEOSChem model simulates 

atmospheric chemical and physical 

processes driven by assimilated 

meteorological observations from the 

NASA’s Goddard Earth Observing 

System (GEOS). This model was run for 

2005 with a grid resolution of 2.0 

degrees x 2.5 degrees (latitudelongitude). The predictions were used to 

provide one-way dynamic boundary 

conditions at three-hour intervals and 

an initial concentration field for the 

coarse scale simulations. 

d. Model Performance Evaluation for 

Ozone and 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 

modeled and observed data. Details on 

the evaluation methodology and the 

calculation of performance statistics are 

provided in the AQMTSD. The results 

indicate that, overall, the predicted 

patterns and day-to-day variations in 

regional ozone levels are similar to what 

was observed with measured data. The 

normalized mean bias for 8-hour daily 

maximum ozone concentrations was 

¥2.9 percent and the normalized mean 

error was 13.2 percent for the months of 

May through September 2005, based on 

an aggregate of observed-predicted pairs 

within the 12 km modeling domain. The 

two 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 9 to 10 

percent at rural sites in the IMPROVE 32

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 

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 

on 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? 

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 


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

34U.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. 

35CAIR was promulgated in 2005 before the 35 

ug/m 3 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. 

36 If there is only one complete design value, then 

the nonattainment and maintenance design values 

are the same. 

37 Design values were only used if they were 

deemed to be officially complete based on CFR 40 

part 50 appendix N. The completeness criteria for 

the annual and 24-hour PM2.5 NAAQS are different. 

Therefore, there are fewer complete sites for the 

annual NAAQS. 

indicate the level of air quality relative 

to the NAAQS. For PM2.5, we evaluated 

concentrations of both the 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/m 3 or less. The 3-year average 

annual mean concentration is computed 

at each site by averaging the daily 

Federal Reference Method (FRM) 

samples by quarter, averaging these 

quarterly averages to obtain an annual 

average, and then averaging the three 

annual averages. The 3-year average 

annual mean concentration is referred to 

as the annual design value. 

The 24-hour average standard is met 

when the 3-year average of the annual 

98th percentile PM2.5 concentration is 

35 μg/m 3 or less. The 3-year average 

mean 98th percentile concentration is 

computed at each site by averaging the 

3 individual annual 98th percentile 

values at each site. The 3-year average 

98th percentile concentration is referred 

to as the 24-hour average design value. 

As described later, the approach for 

projecting future ozone and 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 

design values are accessible at http:// 

www.epagov/airtrends/values.html. 

The procedures for projecting annual 

average PM2.5 and 8-hour ozone 

conform to the methodology in the final 

attainment demonstration modeling 

guidance 34. In the CAIR analysis, EPA 

did not project 24-hour PM2.5 design 

values 35. 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 

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 over-predicted or 

under-predicted. 

Concentrations of PM2.5 in 2012 were 

estimated by applying the 2005 to 2012 

relative change in model-predicted 

PM2.5 species to the (2003–2007) PM2.5

design values. The choice of base period 

design values is consistent with EPA’s 

modeling guidance which recommends 

using the average of the three design 

value periods centered about the 

emissions projection year. Since 2005 

was the base emissions year, we used 

the design value for 2003–2005, 2004– 

2006, and 2005–2007 to represent the 

base period 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 4th years are 

weighted twice, and the 1st and 5th 

years are weighted once. We refer to this 

as the 5-year weighted average 

concentration. 

The 5-year weighted average 

concentrations were used to project 

concentrations for the 2012 base case in 

order to determine which monitoring 

sites are expected to be nonattainment 

in this future year. We projected 2012 

design values for each of 3 year periods 

(i.e., 2003–2005, 2004–2006, and 2003– 

2007) and used the highest of these 

projections to determine which sites are 

expected to have maintenance problems 

in 2012. 

For the analysis of both 

nonattainment and maintenance, 

monitoring sites were included in the 

analysis if they had at least one 

complete design value in the 2003–2007 

period.36 There were 721 monitoring 

sites in the 12 km modeling domain 

which had at least one complete design 

value period for the annual PM2.5

NAAQS, and 736 sites which met this 

criteria for the 24-hour NAAQS.37

EPA followed the procedures 

recommended in the modeling guidance 

for projecting 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 

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 

about 15 percent of FRM monitoring 

sites, spatial interpolation techniques 

are used to calculate species 

concentrations for each FRM monitoring 

site. Speciation data from the IMPROVE 

and Chemical Speciation Network 


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

38For 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. 

39The 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. 

40All of the calculations and assumptions are 

consistent with the default MATS settings (as 

described in the MATS user’s guide and the 

photochemical modeling guidance). Additionally, 

we did not explicitly model salt and therefore the 

salt concentration was held constant from the base 

to future. Blank mass was assumed to be a constant 

mass of 0.5 μg/m3 in both the base and future year. 

41For example, a calculated annual average 

concentration of 14.94753 * * * becomes 14.94 

when digits beyond two places to the right are 

truncated. 

(CSN) were interpolated to each FRM 

monitor location using the Voronoi 

Neighbor Averaging (VNA) technique 

(using MATS). Additional information 

on the VNA interpolation techniques 

and data handling procedures can be 

found in the MATS User’s Guide. After 

the species fractions are calculated for 

each FRM site, the following procedures 

were used to estimate future year design 

values: 

Step 1: Calculate quarterly mean 

concentrations for each of the major 

species components of 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 FRMderived total PM2.5 by the monitored 

fractional composition of PM2.5 species 

for each quarter averaged over 3 years 38

(e.g., 20 percent sulfate fraction 

multiplied by 15 μg/m3 PM2.5 equals 3 

μg/m3 sulfate). 

Step 2: For each quarter, calculate the 

ratio of future year to base year model 

predictions for each of the component 

species. The result is a set of speciesspecific relative response factors (RRF) 

(e.g., assume that the model-predicted 

2005 base year sulfate for a particular 

location is 10.0 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 cells 39 centered at the location of 

the monitor. 

Step 3: For each quarter and each of 

the species, multiply the base year 

quarterly mean component 

concentration (Step 1) by the speciesspecific RRF obtained in Step 2. This 

results in an estimated future year 

quarterly mean concentration for each 

species (e.g., 3 μg/m3 sulfate multiplied 

by 0.8 equals a future sulfate 

concentration of 2.4 μg/m3). 

Step 4: The future year concentrations 

for the remaining species are then 

calculated.40 The future year 

ammonium is calculated based on the 

calculated future year sulfate and nitrate 

concentrations, using a constant value 

for the degree of neutralization of sulfate 

(from the ambient data). The future year 

particle bound water concentration is 

calculated from an empirical formula. 

The inputs to the formula are the future 

year concentrations of sulfate, nitrate, 

and ammonium (from step 3). 

Step 5: Average the four quarterly 

mean future concentrations to obtain the 

future year annual design value 

concentration for each of the component 

species. Sum the species concentrations 

to obtain the future year annual average 

design value for PM2.5. 

Step 6: Calculate the maximum future 

design value by processing each of the 

three base design value periods (2003– 

2005, 2004–2006, and 2005–2007) 

separately. The highest of the three 

future values is the maximum design 

value. The maximum design values are 

used to determine future year 

maintenance sites. 

The preceding procedures for 

determining future year PM2.5

concentrations were applied for each 

FRM site. The calculated annual PM2.5

design values are truncated (i.e., 

discarded) after the second decimal 

place.41 This is consistent with the 

truncation and rounding procedures for 

the annual PM2.5 NAAQS. Any value 

that is greater than or equal to 15.05 

μg/m3 is rounded to 15.1 μg/m3 and is 

considered to be violating the NAAQS. 

Thus, sites with future year annual 

PM2.5 design values of 15.05 μg/m3 or 

greater, based on the projection of 5-year 

weighted average concentrations, are 

predicted to be nonattainment sites. 

Sites with future year maximum design 

values of 15.05 

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. 

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 


erowe on DSK5CLS3C1PROD with PROPOSALS2
45248 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

TABLE IV.C–7—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μG/M3) AT

PROJECTED NONATTAINMENT SITES—Continued 

Monitor ID State County 

Average 

design value 

2003–2007 

Maximum 

design value 

2003–2007 

Average 

design value 

2012 

Maximum 

design value 

2012 

180970081 .................... Indiana ........................ Marion ......................... 16.05 16.36 15.93 16.25 

180970083 .................... Indiana ........................ Marion ......................... 15.90 16.27 15.77 16.15 

211110043 .................... Kentucky ..................... Jefferson ..................... 15.53 15.75 15.19 15.41 

261630015 .................... Michigan ...................... Wayne ......................... 15.88 16.40 15.05 15.55 

261630033 .................... Michigan ...................... Wayne ......................... 17.50 18.16 16.57 17.19 

390170016 .................... Ohio ............................. Butler ........................... 15.74 16.11 15.25 15.61 

390350038 .................... Ohio ............................. Cuyahoga .................... 17.37 18.1 16.26 16.95 

390350045 .................... Ohio ............................. Cuyahoga .................... 16.47 16.98 15.42 15.91 

390350060 .................... Ohio ............................. Cuyahoga .................... 17.11 17.66 16.02 16.55 

390610014 .................... Ohio ............................. Hamilton ...................... 17.29 17.53 16.69 16.93 

390610042 .................... Ohio ............................. Hamilton ...................... 16.85 17.25 16.33 16.71 

390610043 .................... Ohio ............................. Hamilton ...................... 15.55 15.82 15.05 15.32 

390617001 .................... Ohio ............................. Hamilton ...................... 16.17 16.56 15.65 16.03 

390618001 .................... Ohio ............................. Hamilton ...................... 17.54 17.90 16.93 17.27 

420030064 .................... Pennsylvania ............... Allegheny .................... 20.31 20.75 18.90 19.31 

420031301 .................... Pennsylvania ............... Allegheny .................... 16.26 16.57 15.13 15.42 

420070014 .................... Pennsylvania ............... Beaver ......................... 16.38 16.45 15.23 15.30 

420710007 .................... Pennsylvania ............... Lancaster .................... 16.55 17.46 15.19 16.01 

421330008 .................... Pennsylvania ............... York ............................. 16.52 17.25 15.25 15.94 

540110006 .................... West Virginia ............... Cabell .......................... 16.30 16.57 15.25 15.50 

540391005 .................... West Virginia ............... Kanawha ..................... 16.52 16.59 15.28 15.34 

TABLE IV.C–8—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μ/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 ............................... Montgomery .................. 15.54 15.92 15.01 15.37 

391510017 ............... Ohio ............................... Stark .............................. 16.15 16.59 14.99 15.40 

420110011 ............... Pennsylvania ................. Berks ............................. 15.82 16.19 14.77 15.11 

482011035 ............... Texas ............................. Harris ............................. 15.42 15.84 14.74 15.14 

540030003 ............... West Virginia ................. Berkeley ........................ 15.93 16.19 14.95 15.20 

540090005 ............... West Virginia ................. Brooke ........................... 16.52 16.80 14.95 15.22 

540291004 ............... West Virginia ................. Hancock ........................ 15.76 16.64 14.34 15.15 

540490006 ............... West Virginia ................. Marion ........................... 15.03 15.25 14.96 15.18 

(2) Methodology for Projecting Future 

24-Hour 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 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. To 

calculate final future year design values, 

the high quarter for each year is 

identified and then a five year weighted 

average of the high quarters for each site 

was calculated to derive the future year 

design value. 

The following are the steps followed 

for calculating the 2012 base case 24- 

hour 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 


erowe on DSK5CLS3C1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45249 

42High ambient data and model days were 

defined as the top 10 percent days in each quarter 

based on 24-hour concentrations of PM2.5. 43For 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. 

44Since 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. 

45All of the calculations and assumptions are 

consistent with the default MATS settings (as 

described in the MATS user’s guide and the 

photochemical modeling guidance). Additionally, 

we did not explicitly model salt and therefore the 

salt concentration was held constant from the base 

to future. Blank mass was assumed to be a constant 

mass of 0.5 ug/m3 in both the base and future year. 

than or equal to the 98th percentile 

value over the entire year. This results 

in a data set for each year (for up to 5 

years) for each site containing one 

quarter with the observed 98th 

percentile value and three quarters with 

the maximum highest values from each 

quarter that are less than or equal to the 

98th percentile value for the year. All 20 

quarters (i.e., 4 quarters in each of 5 

years) of data are carried through the 

calculations until the high future year 

quarter value is identified in step 6. 

Step 2: In this step we calculate 

quarterly ambient concentrations on 

‘‘high’’ 42 days for each of the major 

component species of 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 FRMderived total PM2.5 mass on the 10 

percent highest days from each quarter, 

by the monitored fractional composition 

of PM2.5 species on the 10 percent 

highest PM2.5 days for each quarter, 

averaged over 3 years 43 (e.g., 20 percent 

sulfate fraction multiplied by 40 μg/m3

PM2.5 equals 8 μg/m3 sulfate). 

Step 3: For each quarter, we calculate 

the ratio of future year (i.e., 2012) to 

base year (i.e., 2005) predictions for 

each component species for the top 10 

percent of days based on predicted 

concentrations of 24-hour 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 

the 2005 predicted sulfate concentration 

on the 10 percent highest PM2.5 days for 

a quarter for a particular location is 20 

μg/m3 and the 2012 base case 

concentration is 16 μg/m3, then RRF for 

sulfate is 0.8). The RRFs are calculated 

based on the modeled concentrations at 

the single grid cell where the monitor is 

located. 

Step 4: For each quarter, we multiply 

the quarterly species concentration (step 

2) by the quarterly 44 species-specific 

RRF obtained in step 3. This leads to an 

estimated future quarterly concentration 

for each component. (e.g., 21.0 μg/m3

nitrate × 0.75 = future nitrate of 15.75 

μg/m3). 

Step 5: The future year concentrations 

for the remaining species are then 

calculated.45 The future year 

ammonium is calculated based on the 

calculated future year sulfate and nitrate 

concentrations, using a constant value 

for the degree of neutralization of sulfate 

(from the ambient data). The future year 

particle bound water concentration is 

calculated from an empirical formula. 

The inputs to the formula are the 

calculated future year concentrations of 

sulfate, nitrate, and ammonium (from 

step 4). 

Step 6: We sum the species 

concentrations to obtain quarterly PM2.5

values. This step is repeated for each 

quarter and for each of the 5 years of 

ambient data. The highest daily value 

(from the 4 quarterly values) for each 

year at each monitor is considered to be 

the estimated future year 98th percentile 

24-hour design value for that year. 

Step 7: The estimated 98th percentile 

values for each of the 5 years are 

averaged over 3 year intervals to create 

the 3 year average design values. These 

design values are averaged to create a 5 

year weighted average for each 

monitoring site. 

Step 8: The maximum future design 

value is calculated by following the 

previous steps for each of the three base 

design value periods (2003–2005, 2004– 

2006, and 2005–2007) separately. The 

highest of the three future values is the 

maximum design value. This maximum 

value is used to identify the 24-hour 

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 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. 

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

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


erowe on DSK5CLS3C1PROD with PROPOSALS2
45250 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

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—Continued 

Monitor ID State County 

Average 

design value 

2003–2007 

Maximum 

design value 

2003–2007 

Average 

design value 

2012 

Maximum 

design value 

2012 

170310057 .................... Illinois .......................... Cook ............................ 37.3 38.6 35.7 37.0 

170310076 .................... Illinois .......................... Cook ............................ 38.0 39.1 36.3 37.3 

170311016 .................... Illinois .......................... Cook ............................ 43.0 46.3 41.0 44.1 

170312001 .................... Illinois .......................... Cook ............................ 37.7 40.6 35.6 38.2 

170313103 .................... Illinois .......................... Cook ............................ 39.6 40.3 38.1 38.7 

170313301 .................... Illinois .......................... Cook ............................ 40.2 43.3 38.2 41.0 

170316005 .................... Illinois .......................... Cook ............................ 39.1 41.8 37.4 39.8 

171190023 .................... Illinois .......................... Madison ....................... 37.3 38.1 39.4 40.2 

171191007 .................... Illinois .......................... Madison ....................... 39.1 40.1 40.0 40.6 

171192009 .................... Illinois .......................... Madison ....................... 34.9 35.9 37.2 38.2 

171193007 .................... Illinois .......................... Madison ....................... 34.0 34.6 36.5 37.3 

180190006 .................... Indiana ........................ Clark ............................ 37.5 39.4 38.1 40.2 

180372001 .................... Indiana ........................ Dubois ......................... 35.3 36.9 36.5 38.0 

180830004 .................... Indiana ........................ Knox ............................ 35.9 36.3 35.9 36.5 

180890022 .................... Indiana ........................ Lake ............................ 38.9 44.0 37.3 42.1 

180890026 .................... Indiana ........................ Lake ............................ 38.4 41.3 36.3 39.3 

180970042 .................... Indiana ........................ Marion ......................... 34.2 35.3 36.3 37.2 

180970043 .................... Indiana ........................ Marion ......................... 38.4 39.9 40.5 42.0 

180970066 .................... Indiana ........................ Marion ......................... 38.3 39.6 40.3 41.8 

180970078 .................... Indiana ........................ Marion ......................... 36.6 37.6 38.7 39.7 

180970079 .................... Indiana ........................ Marion ......................... 35.6 36.7 37.2 38.3 

180970081 .................... Indiana ........................ Marion ......................... 38.2 39.2 40.1 41.1 

180970083 .................... Indiana ........................ Marion ......................... 36.6 37.0 39.0 39.3 

181570008 .................... Indiana ........................ Tippecanoe ................. 35.6 36.7 35.9 36.9 

191630019 .................... Iowa ............................. Scott ............................ 37.1 37.1 36.8 36.8 

210590005 .................... Kentucky ..................... Daviess ....................... 33.8 33.8 37.0 37.0 

211110043 .................... Kentucky ..................... Jefferson ..................... 35.4 36.1 35.8 36.4 

211110044 .................... Kentucky ..................... Jefferson ..................... 36.1 36.6 36.0 36.5 

211110048 .................... Kentucky ..................... Jefferson ..................... 36.4 37.2 35.6 36.4 

245100040 .................... Maryland ..................... Baltimore City .............. 39.0 40.9 36.3 38.3 

245100049 .................... Maryland ..................... Baltimore City .............. 38.1 38.1 35.5 35.5 

261150005 .................... Michigan ...................... Monroe ........................ 38.8 39.6 37.0 38.0 

261250001 .................... Michigan ...................... Oakland ....................... 39.9 40.4 37.9 38.4 

261470005 .................... Michigan ...................... St. Clair ....................... 39.6 40.6 38.4 39.4 

261610008 .................... Michigan ...................... Washtenaw ................. 39.4 40.8 38.1 39.8 

261630015 .................... Michigan ...................... Wayne ......................... 40.1 40.6 38.5 39.1 

261630016 .................... Michigan ...................... Wayne ......................... 42.9 45.4 40.6 43.0 

261630019 .................... Michigan ...................... Wayne ......................... 40.9 41.4 38.6 39.1 

261630033 .................... Michigan ...................... Wayne ......................... 43.8 44.2 42.1 42.6 

261630036 .................... Michigan ...................... Wayne ......................... 37.1 37.9 36.3 36.9 

290990012 .................... Missouri ....................... Jefferson ..................... 33.4 34.2 35.7 36.5 

291831002 .................... Missouri ....................... Saint Charles .............. 33.1 34.7 35.5 37.1 

295100007 .................... Missouri ....................... St. Louis City ............... 33.1 33.5 36.0 36.3 

295100087 .................... Missouri ....................... St. Louis City ............... 34.3 34.7 36.4 36.9 

340171003 .................... New Jersey ................. Hudson ........................ 39.0 40.5 35.7 36.1 

340172002 .................... New Jersey ................. Hudson ........................ 41.4 41.4 38.2 38.2 

340390004 .................... New Jersey ................. Union ........................... 40.4 41.4 36.7 37.2 

360050080 .................... New York .................... Bronx ........................... 38.8 40.2 35.9 36.2 

360610056 .................... New York .................... New York ..................... 39.7 40.6 37.1 38.0 

360610128 .................... New York .................... New York ..................... 39.4 41.8 36.2 38.0 

390170003 .................... Ohio ............................. Butler ........................... 39.2 41.1 40.3 42.3 

390170016 .................... Ohio ............................. Butler ........................... 37.1 37.7 37.5 37.8 

390170017 .................... Ohio ............................. Butler ........................... 37.9 37.9 38.5 38.5 

390171004 .................... Ohio ............................. Butler ........................... 37.1 38.1 37.8 38.6 

390350038 .................... Ohio ............................. Cuyahoga .................... 44.2 47.0 41.2 44.0 

390350045 .................... Ohio ............................. Cuyahoga .................... 38.5 41.5 36.0 39.0 

390350060 .................... Ohio ............................. Cuyahoga .................... 42.1 45.7 39.4 42.8 

390350065 .................... Ohio ............................. Cuyahoga .................... 38.6 41.0 36.5 38.9 

390490024 .................... Ohio ............................. Franklin ....................... 38.5 39.7 36.6 37.6 

390490025 .................... Ohio ............................. Franklin ....................... 38.4 39.1 36.1 36.4 

390610006 .................... Ohio ............................. Hamilton ...................... 37.6 37.6 38.0 38.0 

390610014 .................... Ohio ............................. Hamilton ...................... 38.2 39.4 37.5 38.5 

390610040 .................... Ohio ............................. Hamilton ...................... 36.7 37.7 35.8 36.8 

390610042 .................... Ohio ............................. Hamilton ...................... 37.3 38.2 37.2 38.0 

390610043 .................... Ohio ............................. Hamilton ...................... 35.9 36.2 36.0 36.4 

390617001 .................... Ohio ............................. Hamilton ...................... 38.8 39.6 37.7 38.1 

390618001 .................... Ohio ............................. Hamilton ...................... 40.6 40.9 39.6 40.3 

390811001 .................... Ohio ............................. Jefferson ..................... 41.9 45.5 36.5 39.9 

391130032 .................... Ohio ............................. Montgomery ................ 37.8 40.0 36.3 38.5 


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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—Continued 

Monitor ID State County 

Average 

design value 

2003–2007 

Maximum 

design value 

2003–2007 

Average 

design value 

2012 

Maximum 

design value 

2012 

391530017 .................... Ohio ............................. Summit ........................ 38.0 39.6 35.6 37.2 

420030008 .................... Pennsylvania ............... Allegheny .................... 39.4 39.9 35.9 36.3 

420030064 .................... Pennsylvania ............... Allegheny .................... 64.2 68.2 58.8 62.3 

420030093 .................... Pennsylvania ............... Allegheny .................... 45.6 51.5 41.1 46.2 

420030116 .................... Pennsylvania ............... Allegheny .................... 42.5 42.5 37.1 37.1 

420031008 .................... Pennsylvania ............... Allegheny .................... 41.3 42.8 38.0 39.3 

420031301 .................... Pennsylvania ............... Allegheny .................... 40.3 42.4 36.6 38.6 

420070014 .................... Pennsylvania ............... Beaver ......................... 43.4 44.6 37.7 39.1 

420110011 .................... Pennsylvania ............... Berks ........................... 37.7 39.1 35.8 37.0 

420210011 .................... Pennsylvania ............... Cambria ....................... 39.0 39.4 40.3 40.7 

420430401 .................... Pennsylvania ............... Dauphin ....................... 38.0 39.0 35.7 37.1 

420710007 .................... Pennsylvania ............... Lancaster .................... 40.8 44.0 37.7 40.1 

421330008 .................... Pennsylvania ............... York ............................. 38.2 40.7 35.9 38.8 

471251009 .................... Tennessee .................. Montgomery ................ 36.3 37.5 36.6 37.9 

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

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

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

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

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

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 

Average 

design value 

2012 

Maximum 

design value 

2012 

110010041 ............... Washington DC ............. Washington DC ............. 36.3 37.8 34.0 35.6 

110010042 ............... Washington DC ............. Washington DC ............. 34.9 37.0 33.0 35.6 

170310022 ............... Illinois ............................ Cook .............................. 36.6 38.6 34.9 36.6 

170310050 ............... Illinois ............................ Cook .............................. 36.1 38.0 34.1 35.8 

170314007 ............... Illinois ............................ Cook .............................. 34.3 36.4 33.6 35.7 

171630010 ............... Illinois ............................ Saint Clair ...................... 33.7 34.1 35.3 35.9 

171971002 ............... Illinois ............................ Will ................................. 36.4 37.1 35.1 35.8 

180390003 ............... Indiana ........................... Elkhart ........................... 34.4 36.3 33.8 35.6 

180431004 ............... Indiana ........................... Floyd .............................. 33.2 34.5 34.3 35.7 

181670023 ............... Indiana ........................... Vigo ............................... 34.8 36.1 35.1 36.5 

191390015 ............... Iowa ............................... Muscatine ...................... 36.0 37.7 34.5 36.0 

210290006 ............... Kentucky ........................ Bullitt .............................. 34.6 35.8 35.0 36.3 

211451004 ............... Kentucky ........................ McCracken .................... 33.6 35.9 34.4 36.8 

212270007 ............... Kentucky ........................ Warren ........................... 33.1 35.1 33.7 36.3 

240031003 ............... Maryland ........................ Anne Arundel ................ 35.5 37.4 33.8 36.7 

245100035 ............... Maryland ........................ Baltimore (City) ............. 37.7 39.2 34.7 35.5 

261630001 ............... Michigan ........................ Wayne ........................... 37.8 40.1 35.4 37.8 

295100085 ............... Missouri ......................... St. Louis City ................. 33.2 33.8 35.3 35.7 

360610062 ............... New York ....................... New York ....................... 38.8 41.6 35.3 37.0 

360610079 ............... New York ....................... New York ....................... 37.9 40.2 34.2 36.4 

390350027 ............... Ohio ............................... Cuyahoga ...................... 36.6 38.8 34.5 36.6 

390350034 ............... Ohio ............................... Cuyahoga ...................... 36.5 37.9 33.7 35.7 

390810017 ............... Ohio ............................... Jefferson ........................ 40.7 42.4 35.3 36.8 

390950024 ............... Ohio ............................... Lucas ............................. 36.3 38.6 34.2 36.5 

390950026 ............... Ohio ............................... Lucas ............................. 34.9 36.7 33.6 35.6 

390990014 ............... Ohio ............................... Mahoning ....................... 36.8 38.2 34.2 35.8 

391130031 ............... Ohio ............................... Montgomery .................. 35.7 37.1 34.3 35.6 

391351001 ............... Ohio ............................... Preble ............................ 32.8 33.9 34.3 35.5 

391550007 ............... Ohio ............................... Trumbull ........................ 36.2 37.8 33.9 35.6 

420030095 ............... Pennsylvania ................. Allegheny ....................... 38.7 40.7 34.3 36.6 

420033007 ............... Pennsylvania ................. Allegheny ....................... 37.5 43.1 33.8 38.5 

420410101 ............... Pennsylvania ................. Cumberland ................... 38.0 40.2 35.3 37.0 

421255001 ............... Pennsylvania ................. Washington ................... 38.1 39.9 33.9 35.5 

471650007 ............... Tennessee ..................... Sumner .......................... 33.6 34.5 35.1 36.0 

540090005 ............... West Virginia ................. Brooke ........................... 39.4 41.5 33.9 36.1 

550250047 ............... Wisconsin ...................... Dane .............................. 35.5 36.9 35.1 36.1 

550790059 ............... Wisconsin ...................... Milwaukee ..................... 35.5 37.0 34.8 36.3 

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


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

46As specified in the attainment demonstration 

modeling guidance, if there are less than 10 

modeled days > 85 ppb, then the threshold is 

lowered in 1 ppb increments (to as low as 70 ppb) 

until there are 10 days. If there are less than 5 days 

> 70 ppb, then an RRF calculation is not completed 

for that site. 

(3) Methodology for Projecting Future 

8-Hour Ozone Nonattainment and 

Maintenance 

The following is a brief summary of 

the future year 8-hour average ozone 

calculations. Additional details are 

provided in the modeling guidance, 

MATS documentation, and the 

AQMTSD. 

We are using the base period 2003– 

2007 ambient ozone design value data 

for projecting future year design values. 

The ozone projection procedure is 

relatively simple, since ozone is a single 

species. It is not necessary to interpolate 

ambient ozone data, since ambient 

ozone design values and gridded, 

modeled ozone is all that is needed for 

the projections. 

To project 8-hour ozone design values 

we used the 2005 base year and 2012 

future base case model-predicted ozone 

concentrations to calculate relative 

response factors. The methodology we 

followed is consistent with the 

attainment demonstration modeling 

guidance. The RRFs were applied to the 

2003–2007 ozone design values through 

the following steps: 

Step 1: For each monitoring site we 

calculate the average concentration 

across all days with 8-hour daily 

maximum predictions greater than or 

equal to 85 ppb 46 using the predictions 

in the nine grid cells that include or 

surround the location of the monitoring 

site. The RRF for a site is the ratio of the 

mean prediction in the future year to the 

mean prediction in the 2005 base year. 

The RRFs were calculated on a site-bysite basis. 

Step 2: The RRF for each site is then 

multiplied by the 2003–2007 5-year 

weighted average ambient design value 

for that site, yielding an estimate of the 

future year design value at that 

particular monitoring location. 

Step 3: We calculate the maximum 

future design value by projecting design 

values for each of the three base periods 

(2003–2005, 2004–2006, and 2005– 

2007) separately. The highest of the 

three future values is the maximum 

design value. This maximum value is 

used to identify the 8-hour ozone 

maintenance receptors. 

The preceding procedures for 

determining future year 8-hour average 

ozone design values were applied for 

each ozone monitoring site. The future 

year design values are truncated to 

integers in units of ppb. This approach 

is consistent with the truncation and 

rounding procedures for the 8-hour 

ozone NAAQS. Future year design 

values that are greater than or equal to 

85 ppb are considered to be violating 

the NAAQS. Sites with future year 

5-year weighted average design values 

of 85 ppb or greater are predicted to be 

nonattainment. Sites with future year 

maximum design values of 85 ppb or 

greater are predicted to be future year 

maintenance sites. Note that, as 

described previously for the annual and 

24-hour 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 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 


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

47Zero-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. 

TABLE IV.C–12—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT

PROJECTED MAINTENANCE-ONLY SITES—Continued 

Monitor ID State County 

Average 

design 

value 

2003–2007 

Maximum 

design 

value 2003– 

2007 

Average 

design 

value 

2012 

Maximum 

design 

value 

2012 

90093002 ................... Connecticut ............... New Haven ................ 90 .3 93 82 .9 85 .4 

130890002 ................. Georgia ...................... DeKalb ....................... 88 .7 93 81 .6 85 .6 

131210055 ................. Georgia ...................... Fulton ........................ 91 .7 94 84 .4 86 .5 

361192004 ................. New York ................... Westchester .............. 87 .7 90 84 .7 86 .9 

420170012 ................. Pennsylvania ............. Bucks ......................... 88 92 81 .8 85 .6 

481130069 ................. Texas ......................... Dallas ........................ 87 90 82 .9 85 .8 

481130087 ................. Texas ......................... Dallas ........................ 87 88 84 .6 85 .6 

482010024 ................. Texas ......................... Harris ......................... 88 92 83 .3 87 .1 

482010029 ................. Texas ......................... Harris ......................... 91 .7 93 84 .4 85 .6 

482011015 ................. Texas ......................... Harris ......................... 89 96 83 .7 90 .3 

482011035 ................. Texas ......................... Harris ......................... 86 .3 95 82 90 .3 

482011050 ................. Texas ......................... Harris ......................... 89 .3 92 83 .9 86 .5 

484392003 ................. Texas ......................... Tarrant ....................... 93 .7 95 84 85 .2 

3. How did EPA assess interstate 

contributions to nonattainment and 

maintenance? 

This section documents the 

procedures used by EPA to quantify the 

impact of emissions in specific upwind 

states on air quality concentrations in 

projected downwind nonattainment and 

maintenance locations for annual 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 postprocessing procedures are described in 

this section. 

CAMx employs enhanced source 

apportionment techniques which track 

the formation and transport of ozone 

and particulate matter from specific 

emissions sources and calculates the 

contribution of sources and precursors 

to ozone and PM2.5 for 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 

modeling 47 and other methods to track 

pollutant formation in photochemical 

models. Source apportionment 

completely characterizes source 

contributions to model-estimated ozone 

and PM2.5, which is not possible with an 

emissions sensitivity approach such as 

zero-out, since the change in emissions 

leads 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 sensitivitybased approaches of being more 

computationally efficient. There is 

currently no technical evidence 

showing that one technique is clearly 

superior to the other for evaluating 

contributions to ozone and 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 analysis for the Transport 

Rule 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 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 DC, and 

Wisconsin. There were also several 

other states that are only partially 

contained within the 12 km modeling 

domain (i.e., Colorado, Montana, New 

Mexico, and Wyoming). However, EPA 

did not individually track the emissions 


erowe on DSK5CLS3C1PROD with PROPOSALS2
45254 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

48The 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. 

49Ozone contributions are averaged over a 

minimum of 5 days. If there are fewer than 5 days 

greater than 85 ppb at a receptor, then the 85 ppb 

criterion is lowered in 1 ppb increments until there 

are 5 days of data for use in the calculations. If there 

are fewer than 5 modeled days greater than 70 ppb 

at the receptor, then the receptor is not used in the 

contribution calculations. 

or assess the contribution from 

emissions in these states. 

In contrast to CAIR, all contributions 

to downwind nonattainment and 

maintenance receptors for the Transport 

Rule were calculated using a relative 

approach. This is similar to the 

approach used to calculate future year 

design values, as described in section 

IV.C.2.a. In CAIR we used absolute and 

relative metrics to examine air quality 

contributions. Although absolute 

contributions are useful for certain 

applications, there are advantages of 

examining the relative contributions for 

both ozone and 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). 

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 CAMxpredicted absolute 2012 base case 

concentration of the same species. The 

PSAT-derived ratios were then 

multiplied by the corresponding species 

component concentrations comprising 

the 2012 base case 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- 

hour calculations, only the upwind 

contribution to the highest quarter at 

each receptor was used (i.e., highest 

quarter based on 2012 PM2.5 mass). For 

both annual and 24-hour PM2.5, the total 

PM2.5 mass contribution was calculated 

by summing the contributions of sulfate, 

nitrate, ammonium, and particle bound 

water. 48 Details on the procedures for 

calculating the contribution metrics are 

provided in the AQMTSD. 

b. 8-Hour Ozone Contribution Modeling 

Approach 

EPA used the CAMX Ozone Source 

Apportionment Technique (OSAT) in 

order to calculate downwind 8-hour 

ozone contributions to nonattainment 

and maintenance. OSAT tracks the 

formation of ozone from 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 downwind 

ozone concentrations. There are several 

post-processing steps needed to 

transform the raw model outputs to 

ozone downwind contributions. We 

developed and applied several postprocessing steps to transform the OSAT 

modeling outputs to ozone 

contributions at downwind receptors. 

The approach for ozone was similar to 

the approach for PM2.5 in that the OSAT 

model outputs were processed using 

MATS along with other post-processing 

software to calculate the contribution of 

each upwind state to each downwind 

nonattainment and/or maintenance 

receptor. This process involved 

calculating a ratio which uses the 

OSAT-predicted absolute contribution 

of ozone coupled with the CAMxpredicted absolute 2012 base case ozone 

concentration. The OSAT-derived ratios 

were then multiplied by the 

corresponding 2012 base case ozone 

design value. The contributions to each 

downwind receptor are averaged across 

all days with modeled 2012 base case 

concentrations greater than 85 ppb 49 (at 

the given receptor). Details on the 

procedures for calculating the 

contribution metrics are provided in the 

AQMTSD. 

c. Use of Projected Nonattainment and 

Maintenance Contributions 

The previous steps provide the details 

for calculating 8-hour ozone and annual 

and 24-hour PM2.5 contributions to all 

downwind receptors. After the postprocessing of the model results is 

complete, we then evaluate the 

contributions of each upwind state to 

nonattainment and maintenance 

receptors. The nonattainment receptors 

are those monitoring sites which are 

projected to exceed the NAAQS in the 

2012 base case, based on 5-year 

weighted average design values. The 

maintenance receptors are those 

monitoring sites which are projected to 

exceed the NAAQS in the 2012 base 

case based on the highest design value 

period. The upwind ozone and 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 


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

contribution to a future year (2012) 

downwind nonattainment receptor. The 

maximum contribution to maintenance 

is calculated based on the single largest 

contribution to a future year (2012) 

downwind maintenance receptor. Since 

the contributions are calculated 

independently for each receptor, the 

upwind contribution to maintenance 

can sometimes be larger than the 

contribution to nonattainment, and vice 

versa. This also means that maximum 

contributions to nonattainment can be 

below the threshold while maximum 

contributions to maintenance may be at 

or above the threshold, or vice versa. 

4. What are the estimated interstate 

contributions to annual 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/m3or 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 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 largest 

contribution from each state to annual 

PM2.5 nonattainment in downwind sites 

is provided in Table IV.C–13. The 

largest 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. 

TABLE IV.C–13—LARGEST CONTRIBUTION TO DOWNWIND ANNUAL PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE

FOR EACH OF 37 STATES

Upwind state 

Largest 

downwind contribution to nonattainment for annual 

PM2.5 (μg/m3) 

Largest 

downwind contribution to maintenance 

for annual PM2.5

(μg/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/Washington, D.C. ..................................................................................................................... 0.63 0.56 

Massachusetts ......................................................................................................................................... 0.07 0.13 

Michigan ................................................................................................................................................... 0.72 0.71 

Minnesota ................................................................................................................................................ 0.19 0.17 

Mississippi ................................................................................................................................................ 0.07 0.03 

Missouri .................................................................................................................................................... 1.38 0.27 

Nebraska .................................................................................................................................................. 0.08 0.06 

New Hampshire ....................................................................................................................................... 0.01 0.02 

New Jersey .............................................................................................................................................. 0.34 0.68 

New York ................................................................................................................................................. 0.49 0.47 

North Carolina .......................................................................................................................................... 0.19 0.11 

North Dakota ............................................................................................................................................ 0.05 0.05 

Ohio ......................................................................................................................................................... 1.49 2.03 

Oklahoma ................................................................................................................................................. 0.08 0.05 

Pennsylvania ............................................................................................................................................ 0.83 1.60 

Rhode Island ............................................................................................................................................ 0.01 0.01 

South Carolina ......................................................................................................................................... 0.26 0.04 

South Dakota ........................................................................................................................................... 0.02 0.02 

Tennessee ............................................................................................................................................... 0.68 0.64 

Texas ....................................................................................................................................................... 0.13 0.06 

Vermont ................................................................................................................................................... 0.00 0.00 

Virginia ..................................................................................................................................................... 0.36 0.37 


erowe on DSK5CLS3C1PROD with PROPOSALS2
45256 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

50EPA 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. 

51As 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. 

TABLE IV.C–13—LARGEST CONTRIBUTION TO DOWNWIND ANNUAL PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE

FOR EACH OF 37 STATES—Continued 

Upwind state 

Largest 

downwind contribution to nonattainment for annual 

PM2.5 (μg/m3) 

Largest 

downwind contribution to maintenance 

for annual PM2.5

(μg/m3) 

West Virginia ............................................................................................................................................ 0.98 1.17 

Wisconsin ................................................................................................................................................. 0.46 0.42 

Based on the state-by-state 

contribution analysis, there are 22 states 

and the District of Columbia 50 which 

contribute 0.15 μg/m3 or more to 

downwind annual PM2.5 nonattainment. 

These states are: Alabama, Delaware, the 

District of Columbia, Florida, Georgia, 

Illinois, Indiana, Iowa, Kentucky, 

Maryland, Michigan, Minnesota, 

Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Virginia, West 

Virginia, and Wisconsin. In Table IV.C– 

14, we provide a list of the downwind 

nonattainment sites to which each 

upwind state contributes 0.15 μg/m3 or 

more (i.e., the upwind state to 

downwind nonattainment ‘‘linkages’’). 

There are 19 states and the District of 

Columbia 51 which contribute 0.15 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’’). 


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TABLE IV.C–14—UPWIND

STATE TO

DOWNWIND

NONATTAINMENT

SITE ‘‘LINKAGES’’ FOR

ANNUAL PM2.5

Upwind State Number of linkages 

Counties containing downwind 24-hour 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 (171630010) 

Jefferson, KY (211110043) 

Wayne, MI (261630015) 

Wayne, MI (261630033) 

Butler, OH (390170016) 

Cuyahoga, OH (390350038) 

Cuyahoga, OH (390350045) 

Cuyahoga, OH (390350060) 

Hamilton, OH (390618001) 

Hamilton, OH (390610014) 

Hamilton, OH (390610042) 

Hamilton, OH (390610043) 

Hamilton, OH (390617001) 

Allegheny, PA (420030064) 

Allegheny, PA (420031301) 

Beaver, PA (420070014) 

Lancaster, PA (420710007) 

York, PA (421330008) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

Iowa ........................................................................... 4 Cook, IL 

(170310052) 

Madison, IL (171191007) 

Saint Clair, IL (171630010) 

Dubois, IN (180372001) 

Kentucky .................................................................... 31 Jefferson, AL 

(10730023) 

Jefferson, AL (10732003) 

Bibb, GA (130210007) 

Clayton, GA (130630091) 

Fulton, GA (131210039) 

Cook, IL (170310052) 

Madison, IL (171191007) 

Saint Clair, IL (171630010) 

Clark, IN (180190006) 

Dubois, IN (180372001) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Wayne, MI (261630015) 

Wayne, MI (261630033) 

Butler, OH (390170016) 

Cuyahoga, OH (390350038) 

Cuyahoga, OH (390350045) 

Cuyahoga, OH (390350060) 

Hamilton, OH (390610014) 

Hamilton, OH (390610042) 

Hamilton, OH (390610043) 

Hamilton, OH (390617001) 

Hamilton, OH (390618001) 

Allegheny, PA (420030064) 

Allegheny, PA (420031301) 

Beaver, PA (420070014) 

Lancaster, PA (420710007) 

York, PA (421330008) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

Maryland .................................................................... 2 Lancaster, PA 

(420710007) 

York, PA (421330008) 

Michigan .................................................................... 25 Cook, IL 

(170310052) 

Madison, IL (171191007) 

Saint Clair, IL (171630010) 

Clark, IN (180190006) 

Dubois, IN (180372001) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Jefferson, KY (211110043) 

Butler, OH (390170016) 

Cuyahoga, OH (390350038) 

Cuyahoga, OH (390350045) 

Cuyahoga, OH (390350060) 

Hamilton, OH (390610014) 

Hamilton, OH (390610042) 

Hamilton, OH (390610043) 

Hamilton, OH (390617001) 

Hamilton, OH (390618001) 

Allegheny, PA (420030064) 

Allegheny, PA (420031301) 

Beaver, PA (420070014) 

Lancaster, PA (420710007) 

York, PA (421330008) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

Minnesota .................................................................. 1 Cook, IL 

(170310052) 

Missouri ..................................................................... 17 Cook, IL 

(170310052) 

Madison, IL (171191007) 

Saint Clair, IL (171630010) 

Clark, IN (180190006) 

Dubois, IN (180372001) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Jefferson, KY (211110043) 

Butler, OH (390170016) 

Hamilton, OH (390610014) 

Hamilton, OH (390610042) 

Hamilton, OH (390610043) 

Hamilton, OH (390617001) 

Hamilton, OH (390618001) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

New Jersey ............................................................... 2 Lancaster, PA 

(420710007) 

York, PA (421330008) 


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45258 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

TABLE IV.C–14—UPWIND

STATE TO

DOWNWIND

NONATTAINMENT

SITE ‘‘LINKAGES’’ FOR

ANNUAL PM2.5—Continued 

Upwind State Number of linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

New York ................................................................... 8 Cuyahoga, OH 

(390350038) 

Cuyahoga, OH (390350045) 

Cuyahoga, OH (390350060) 

Allegheny, PA (420030064) 

Allegheny, PA (420031301) 

Beaver, PA (420070014) 

Lancaster, PA (420710007) 

York, PA (421330008) 

North Carolina ........................................................... 3 Bibb, GA 

(130210007) 

Clayton, GA (130630091) 

Fulton, GA (131210039) 

Ohio ........................................................................... 23 Jefferson, AL 

(10730023) 

Jefferson, AL (10732003) 

Bibb, GA (130210007) 

Clayton, GA (130630091) 

Fulton, GA (131210039) 

Cook, IL (170310052) 

Madison, IL (171191007) 

Saint Clair, IL (171630010) 

Clark, IN (180190006) 

Dubois, IN (180372001) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Jefferson, KY (211110043) 

Wayne, MI (261630015) 

Wayne, MI (261630033) 

Allegheny, PA (420030064) 

Allegheny, PA (420031301) 

Beaver, PA (420070014) 

Lancaster, PA (420710007) 

York, PA (421330008) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

Pennsylvania ............................................................. 25 Bibb, GA 

(130210007) 

Clayton, GA (130630091) 

Fulton, GA (131210039) 

Cook, IL (170310052) 

Madison, IL (171191007) 

Saint Clair, IL (171630010) 

Clark, IN (180190006) 

Dubois, IN (180372001) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Jefferson, KY (211110043) 

Wayne, MI (261630015) 

Wayne, MI (261630033) 

Butler, OH (390170016) 

Cuyahoga, OH (390350038) 

Cuyahoga, OH (390350045) 

Cuyahoga, OH (390350060) 

Hamilton, OH (390610014) 

Hamilton, OH (390610042) 

Hamilton, OH (390610043) 

Hamilton, OH (390617001) 

Hamilton, OH (390618001) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

South Carolina .......................................................... 3 Bibb, GA 

(130210007) 

Clayton, GA (130630091) 

Fulton, GA (131210039) 

Tennessee ................................................................. 29 Jefferson, AL 

(10730023) 

Jefferson, AL (10732003) 

Bibb, GA (130210007) 

Clayton, GA (130630091) 

Fulton, GA (131210039) 

Clark, IN (180190006) 

Madison, IL (171191007) 

Saint Clair, IL (171630010) 

Dubois, IN (180372001) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Jefferson, KY (211110043) 

Wayne, MI (261630015) 

Wayne, MI (261630033) 

Butler, OH (390170016) 

Cuyahoga, OH (390350038) 

Cuyahoga, OH (390350045) 

Cuyahoga, OH (390350060) 

Hamilton, OH (390610014) 

Hamilton, OH (390610042) 

Hamilton, OH (390610043) 

Hamilton, OH (390617001) 

Hamilton, OH (390618001) 

Allegheny, PA (420030064) 

Allegheny, PA (420031301) 

Beaver, PA (420070014) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

Virginia ...................................................................... 4 Lancaster, PA 

(420710007) 

York, PA (421330008) 

Cabell, WV (540110006) 

Kanawha, WV (540391005) 

West Virginia ............................................................. 25 Fulton, GA 

(131210039) 

Bibb, GA (130210007) 

Clayton, GA (130630091) 

Clark, IN (180190006) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Dubois, IN (180372001) 

Jefferson, KY (211110043) 

Wayne, MI (261630015) 

Wayne, MI (261630033) 

Butler, OH (390170016) 

Cuyahoga, OH (390350038) 

Cuyahoga, OH (390350045) 

Cuyahoga, OH (390350060) 

Hamilton, OH (390610014) 

Hamilton, OH (390610042) 

Hamilton, OH (390610043) 

Hamilton, OH (390617001) 

Hamilton, OH (390618001) 

Allegheny, PA (420030064) 

Allegheny, PA (420031301) 

Beaver, PA (420070014) 

Lancaster, PA (420710007) 

York, PA (421330008) 

Wisconsin .................................................................. 8 Cook, IL 

(170310052) 

Dubois, IN (180372001) 

Marion, IN (180970078) 

Marion, IN (180970081) 

Marion, IN (180970083) 

Wayne, MI (261630015) 

Wayne, MI (261630033) 

Cuyahoga, OH (390350045) 


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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45259 

TABLE IV.C–15—UPWIND

STATE TO

DOWNWIND

MAINTENANCE

SITE ‘‘LINKAGES’’ FOR

ANNUAL PM2.5

Upwind State Number of linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Alabama .................................................................... 1 Jefferson, KY 

(211110044) 

Georgia ...................................................................... 1 Jefferson, KY 

(211110044) 

Illinois ........................................................................ 13 Jefferson, KY 

(211110044) 

Cuyahoga, OH (390350027) 

Cuyahoga, OH (390350065) 

Hamilton, OH (390610040) 

Jefferson, OH (390811001) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

Berks, PA (420110011) 

Harris, TX (482011035) 

Berkeley, WV (540030003) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Indiana ....................................................................... 16 Cook, IL 

(170313301) 

Cook, IL (170316005) 

Jefferson, KY (211110044) 

New York, NY (360610056) 

Cuyahoga, OH (390350027) 

Cuyahoga, OH (390350065) 

Hamilton, OH (390610040) 

Jefferson, OH (390811001) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

Berks, PA (420110011) 

Harris, TX (482011035) 

Berkeley, WV (540030003) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Iowa ........................................................................... 2 Cook, IL 

(170313301) 

Cook, IL (170316005) 

Kentucky .................................................................... 12 Cook, IL 

(170313301) 

Cook, IL (170316005) 

Cuyahoga, OH (390350027) 

Cuyahoga, OH (390350065) 

Hamilton, OH (390610040) 

Jefferson, OH (390811001) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

Berkeley, WV (540030003) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Louisiana ................................................................... 1 Harris, TX 

(482011035) 

Maryland .................................................................... 2 Berks, PA 

(420110011) 

Berkeley, WV (540030003) 

Michigan .................................................................... 15 Cook, IL 

(170313301) 

Cook, IL (170316005) 

Jefferson, KY (211110044) 

New York, NY (360610056) 

Cuyahoga, OH (390350027) 

Cuyahoga, OH (390350065) 

Hamilton, OH (390610040) 

Jefferson, OH (390811001) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

Berks, PA (420110011) 

Berkeley, WV (540030003) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Minnesota .................................................................. 1 Cook, IL 

(170316005) 

Missouri ..................................................................... 6 Cook, IL 

(170313301) 

Cook, IL (170316005) 

Jefferson, KY (211110044) 

Hamilton, OH (390610040) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

New Jersey ............................................................... 2 New York, NY 

(360610056) 

Berks, PA (420110011) 

New York ................................................................... 9 Cuyahoga, OH 

(390350027) 

Cuyahoga, OH (390350065) 

Jefferson, OH (390811001) 

Stark, OH (391510017) 

Berks, PA (420110011) 

Berkeley, WV (540030003) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Ohio ........................................................................... 9 Cook, IL 

(170313301) 

Cook, IL (170316005) 

Jefferson, KY (211110044) 

New York, NY (360610056) 

Berks, PA (420110011) 

Berkeley, WV (540030003) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Pennsylvania ............................................................. 14 Cook, IL 

(170313301) 

Cook, IL (170316005) 

Jefferson, KY (211110044) 

New York, NY (360610056) 

Cuyahoga, OH (390350027) 

Cuyahoga, OH (390350065) 

Hamilton, OH (390610040) 

Jefferson, OH (390811001) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

Berkeley, WV (540030003) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Tennessee ................................................................. 10 Jefferson, KY 

(211110044) 

Cuyahoga, OH (390350027) 

Cuyahoga, OH (390350065) 

Hamilton, OH (390610040) 

Jefferson, OH (390811001) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

Brooke, WV (540090005) 

Hancock, WV (540291004) 

Marion, WV (540490006) 

Virginia ...................................................................... 4 New York, NY 

(360610056) 

Berks, PA (420110011) 

Berkeley, WV (540030003) 

Marion, WV (540490006) 

West Virginia ............................................................. 9 Jefferson, KY 

(211110044) 

New York, NY (360610056) 

Cuyahoga, OH (390350027) 

Cuyahoga, OH (390350065) 

Hamilton, OH (390610040) 

Jefferson, OH (390811001) 

Montgomery, OH (391130032) 

Stark, OH (391510017) 

Berks, PA (420110011) 


erowe on DSK5CLS3C1PROD with PROPOSALS2
45260 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

TABLE IV.C–15—UPWIND

STATE TO

DOWNWIND

MAINTENANCE

SITE ‘‘LINKAGES’’ FOR

ANNUAL PM2.5—Continued 

Upwind State Number of linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Wisconsin .................................................................. 2 Cook, IL 

(170313301) 

Cook, IL (170316005) 


erowe on DSK5CLS3C1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45261 

52As noted above, we combined Maryland and 

the District of Columbia as a single entity in our 

contribution modeling. This is a logical approach 

because of the small size of the District of Columbia 

and, hence, its emissions and its close proximity to 

Maryland. 

For 24-hour 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 largest 

contribution from each state to 24-hour 

PM2.5 nonattainment in downwind sites 

is provided in Table IV.C–16. The 

largest 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—LARGEST CONTRIBUTION TO DOWNWIND 24-HOUR PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE

FOR EACH OF 37 STATES

Upwind State 

Largest downwind contribution to nonattainment for 

24-hour PM2.5

(μg/m3) 

Largest downwind contribution to maintenance for 24- 

hour PM2.5

(μg/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 

Maryland/Washington, DC ....................................................................................................................................... 2.63 1.82 

Massachusetts ......................................................................................................................................................... 0.67 0.71 

Michigan ................................................................................................................................................................... 2.35 3.35 

Minnesota ................................................................................................................................................................ 0.91 0.86 

Mississippi ................................................................................................................................................................ 0.09 0.04 

Missouri .................................................................................................................................................................... 5.03 4.82 

Nebraska .................................................................................................................................................................. 0.62 0.39 

New Hampshire ....................................................................................................................................................... 0.21 0.23 

New Jersey .............................................................................................................................................................. 2.69 4.74 

New York ................................................................................................................................................................. 5.82 1.17 

North Carolina .......................................................................................................................................................... 0.50 0.45 

North Dakota ............................................................................................................................................................ 0.27 0.15 

Ohio ......................................................................................................................................................................... 5.84 5.56 

Oklahoma ................................................................................................................................................................. 0.16 0.21 

Pennsylvania ............................................................................................................................................................ 3.67 4.86 

Rhode Island ............................................................................................................................................................ 0.05 0.06 

South Carolina ......................................................................................................................................................... 0.19 0.19 

South Dakota ........................................................................................................................................................... 0.13 0.09 

Tennessee ............................................................................................................................................................... 3.92 4.70 

Texas ....................................................................................................................................................................... 0.21 0.28 

Vermont ................................................................................................................................................................... 0.06 0.07 

Virginia ..................................................................................................................................................................... 1.32 2.26 

West Virginia ............................................................................................................................................................ 3.51 4.83 

Wisconsin ................................................................................................................................................................. 0.80 1.01 

Based on the state-by-state 

contribution analysis, there are 24 states 

and the District of Columbia 52 which 

contribute 0.35 μg/m3 or more to 

downwind 24-hour PM2.5

nonattainment. These states are: 

Alabama, the District of Columbia, 

Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Massachusetts, 

Michigan, Minnesota, Missouri, 

Nebraska, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, 

Tennessee, Virginia, West Virginia, and 

Wisconsin. In Table IV.C–17, we 

provide a list of the downwind 

nonattainment counties to which each 

upwind state contributes 0.35 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’’). 


erowe on DSK5CLS3C1PROD with PROPOSALS2
45262 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

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) 

Cuyahoga, OH 

(390350060) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610006) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390610040) 

Hamilton, OH 

(390610042) 

Hamilton, OH 

(390610043) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Jefferson, OH 

(390811001) 

Montgomery, OH 

(391130032) 

Summit, OH 

(391530017) 

Allegheny, PA 

(420030064) 

Allegheny, PA 

(420030093) 

Allegheny, PA 

(420030116) 

Allegheny, PA 

(420031008) 

Allegheny, PA 

(420031301) 

Beaver, PA 

(420070014) 

Berks, PA 

(420110011) 

Cambria, PA 

(420210011) 

Montgomery, TN 

(471251009) 

Brooke, WV 

(540090011) 

Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Indiana ........................ 75 Jefferson, AL 

(10730023) 

Jefferson, AL 

(10732003) 

New Haven, CT 

(90091123) 

Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171190023) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Scott, IA 

(191630019) 

Daviess, KY 

(210590005) 

Jefferson, KY 

(211110043) 

Jefferson, KY 

(211110044) 

Jefferson, KY 

(211110048) 

Monroe, MI 

(261150005) 

Oakland, MI 

(261250001) 

St. Clair, MI 

(261470005) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630015) 

Wayne, MI 

(261630016) 

Wayne, MI 

(261630019) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Jefferson, MO 

(290990012) 

Saint Charles, MO 

(291831002) 

St. Louis City, MO 

(295100007) 

St. Louis City, MO 

(295100087) 

Hudson, NJ 

(340171003) 

Union, NJ 

(340390004) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Butler, OH 

(390170003) 

Butler, OH 

(390170016) 

Butler, OH 

(390170017) 

Butler, OH 

(390171004) 

Cuyahoga, OH 

(390350038) 

Cuyahoga, OH 

(390350045) 

Cuyahoga, OH 

(390350060) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610006) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390610040) 

Hamilton, OH 

(390610042) 

Hamilton, OH 

(390610043) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Jefferson, OH 

(390811001) 

Montgomery, OH 

(391130032) 

Summit, OH 

(391530017) 

Allegheny, PA 

(420030008) 

Allegheny, PA 

(420030064) 

Allegheny, PA 

(420030093) 

Allegheny, PA 

(420030116) 

Allegheny, PA 

(420031008) 

Allegheny, PA 

(420031301) 

Beaver, PA 

(420070014) 

Berks, PA 

(420110011) 

Cambria, PA 

(420210011) 

Dauphin, PA 

(420430401) 

York, PA 

(421330008) 

Montgomery, TN 

(471251009) 

Brooke, WV 

(540090011) 

Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Iowa ............................ 17 Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171191007) 

Lake, IN 

(180890022) 

Lake, IN 

(180890026) 

Jefferson, MO 

(290990012) 

St. Louis City, MO 

(295100007) 

Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Kansas ....................... 3 Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790099) 

Kentucky ..................... 81 Jefferson, AL 

(10730023) 

Jefferson, AL 

(10732003) 

New Haven, CT 

(90091123) 

Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171190023) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Clark, IN 

(180190006) 

Dubois, IN 

(180372001) 

Knox, IN 

(180830004) 

Lake, IN 

(180890026) 

Marion, IN 

(180970042) 

Marion, IN 

(180970043) 

Marion, IN 

(180970066) 

Marion, IN 

(180970078) 

Marion, IN 

(180970079) 

Marion, IN 

(180970081) 

Marion, IN 

(180970083) 

Tippecanoe, IN 

(181570008) 

Scott, IA 

(191630019) 

Monroe, MI 

(261150005) 

Oakland, MI 

(261250001) 


erowe on DSK5CLS3C1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45263 

TABLE IV.C–17—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued 

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

St. Clair, MI 

(261470005) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630015) 

Wayne, MI 

(261630016) 

Wayne, MI 

(261630019) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Jefferson, MO 

(290990012) 

Saint Charles, MO 

(291831002) 

St. Louis City, MO 

(295100007) 

St. Louis City, MO 

(295100087) 

Hudson, NJ 

(340171003) 

Union, NJ 

(340390004) 

Bronx, NY 

(360050080) 

New York, NY 

(360610128) 

Butler, OH 

(390170003) 

Butler, OH 

(390170016) 

Butler, OH 

(390170017) 

Butler, OH 

(390171004) 

Cuyahoga, OH 

(390350038) 

Cuyahoga, OH 

(390350045) 

Cuyahoga, OH 

(390350060) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610006) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390610040) 

Hamilton, OH 

(390610042) 

Hamilton, OH 

(390610043) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Jefferson, OH 

(390811001) 

Montgomery, OH 

(391130032) 

Summit, OH 

(391530017) 

Allegheny, PA 

(420030008) 

Allegheny, PA 

(420030064) 

Allegheny, PA 

(420030093) 

Allegheny, PA 

(420030116) 

Allegheny, PA 

(420031008) 

Allegheny, PA 

(420031301) 

Beaver, PA 

(420070014) 

Berks, PA 

(420110011) 

Cambria, PA 

(420210011) 

York, PA 

(421330008) 

Montgomery, TN 

(471251009) 

Brooke, WV 

(540090011) 

Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Maryland ..................... 11 New Haven, CT 

(90091123) 

Hudson, NJ 

(340171003) 

Hudson, NJ 

(340172002) 

Union, NJ 

(340390004) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Berks, PA 

(420110011) 

Dauphin, PA 

(420430401) 

Lancaster, PA 

(420710007) 

York, PA 

(421330008) 

Massachusetts ........... 3 New Haven, CT 

(90091123) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Michigan ..................... 48 Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171190023) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Knox, IN 

(180830004) 

Lake, IN 

(180890022) 

Lake, IN 

(180890026) 

Scott, IA 

(191630019) 

Jefferson, MO 

(290990012) 

Saint Charles, MO 

(291831002) 

St. Louis City, MO 

(295100007) 

St. Louis City, MO 

(295100087) 

New York, NY 

(360610128) 

Cuyahoga, OH 

(390350038) 

Cuyahoga, OH 

(390350045) 

Cuyahoga, OH 

(390350060) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Jefferson, OH 

(390811001) 

Montgomery, OH 

(391130032) 

Summit, OH 

(391530017) 

Allegheny, PA 

(420030008) 

Allegheny, PA 

(420030064) 

Allegheny, PA 

(420030093) 

Allegheny, PA 

(420030116) 

Allegheny, PA 

(420031008) 

Allegheny, PA 

(420031301) 

Beaver, PA 

(420070014) 

Cambria, PA 

(420210011) 

Dauphin, PA 

(420430401) 

Montgomery, TN 

(471251009) 

Brooke, WV 

(540090011) 

Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Minnesota ................... 4 Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Missouri ...................... 56 Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171190023) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Clark, IN 

(180190006) 

Dubois, IN 

(180372001) 

Knox, IN 

(180830004) 

Lake, IN 

(180890022) 

Lake, IN 

(180890026) 

Marion, IN 

(180970042) 

Marion, IN 

(180970043) 

Marion, IN 

(180970066) 

Marion, IN 

(180970078) 

Marion, IN 

(180970079) 

Marion, IN 

(180970081) 

Marion, IN 

(180970083) 

Tippecanoe, IN 

(181570008) 

Scott, IA 

(191630019) 

Daviess, KY 

(210590005) 

Jefferson, KY 

(211110043) 

Jefferson, KY 

(211110044) 

Jefferson, KY 

(211110048) 

Monroe, MI 

(261150005) 

Oakland, MI 

(261250001) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630015) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Butler, OH 

(390170003) 

Butler, OH 

(390170016) 

Butler, OH 

(390170017) 

Butler, OH 

(390171004) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610006) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390610040) 

Hamilton, OH 

(390610042) 

Hamilton, OH 

(390610043) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Montgomery, OH 

(391130032) 

Allegheny, PA 

(420030116) 

Montgomery, TN 

(471251009) 

Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Nebraska .................... 3 Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790099) 

New Jersey ................ 9 New Haven, CT 

(90091123) 

Baltimore City, MD 

(245100049) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Berks, PA 

(420110011) 

Dauphin, PA 

(420430401) 

Lancaster, PA 

(420710007) 

York, PA 

(421330008) 

New York .................... 23 New Haven, CT 

(90091123) 

Baltimore City, MD 

(245100040) 

Baltimore City, MD 

(245100049) 

St. Clair, MI 

(261470005) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630016) 

Wayne, MI 

(261630019) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Hudson, NJ 

(340171003) 

Hudson, NJ 

(340172002) 

Union, NJ 

(340390004) 

Cuyahoga, OH 

(390350038) 

Cuyahoga, OH 

(390350045) 

Cuyahoga, OH 

(390350060) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Summit, OH 

(391530017) 

Berks, PA 

(420110011) 

Dauphin, PA 

(420430401) 

Lancaster, PA 

(420710007) 

York, PA 

(421330008) 


erowe on DSK5CLS3C1PROD with PROPOSALS2
45264 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

TABLE IV.C–17—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued 

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

North Carolina ............ 11 Baltimore City, MD 

(245100040) 

Baltimore City, MD 

(245100049) 

Hudson, NJ 

(340171003) 

Hudson, NJ 

(340172002) 

Union, NJ 

(340390004) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

Berks, PA 

(420110011) 

Dauphin, PA 

(420430401) 

Lancaster, PA 

(420710007) 

York, PA 

(421330008) 

Ohio ............................ 72 Jefferson, AL 

(10730023) 

Jefferson, AL 

(10732003) 

New Haven, CT 

(90091123) 

Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171190023) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Clark, IN 

(180190006) 

Dubois, IN 

(180372001) 

Knox, IN 

(180830004) 

Lake, IN 

(180890022) 

Lake, IN 

(180890026) 

Marion, IN 

(180970042) 

Marion, IN 

(180970043) 

Marion, IN 

(180970066) 

Marion, IN 

(180970078) 

Marion, IN 

(180970079) 

Marion, IN 

(180970081) 

Marion, IN 

(180970083) 

Tippecanoe, IN 

(181570008) 

Scott, IA 

(191630019) 

Daviess, KY 

(210590005) 

Jefferson, KY 

(211110043) 

Jefferson, KY 

(211110044) 

Jefferson, KY 

(211110048) 

Baltimore City, MD 

(245100040) 

Baltimore City, MD 

(245100049) 

Monroe, MI 

(261150005) 

Oakland, MI 

(261250001) 

St. Clair, MI 

(261470005) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630015) 

Wayne, MI 

(261630016) 

Wayne, MI 

(261630019) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Jefferson, MO 

(290990012) 

Saint Charles, MO 

(291831002) 

St. Louis City, MO 

(295100007) 

St. Louis City, MO 

(295100087) 

Hudson, NJ 

(340171003) 

Hudson, NJ 

(340172002) 

Union, NJ 

(340390004) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Allegheny, PA 

(420030008) 

Allegheny, PA 

(420030064) 

Allegheny, PA 

(420030093) 

Allegheny, PA 

(420030116) 

Allegheny, PA 

(420031008) 

Allegheny, PA 

(420031301) 

Beaver, PA 

(420070014) 

Berks, PA 

(420110011) 

Cambria, PA 

(420210011) 

Dauphin, PA 

(420430401) 

Lancaster, PA 

(420710007) 

York, PA 

(421330008) 

Montgomery, TN 

(471251009) 

Brooke, WV 

(540090011) 

Milwaukee, WI 

(550790010) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Pennsylvania .............. 77 Jefferson, AL 

(10730023) 

Jefferson, AL 

(10732003) 

New Haven, CT 

(90091123) 

Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Madison, IL 

(171190023) 

Clark, IN 

(180190006) 

Dubois, IN 

(180372001) 

Knox, IN 

(180830004) 

Lake, IN 

(180890026) 

Marion, IN 

(180970042) 

Marion, IN 

(180970043) 

Marion, IN 

(180970066) 

Marion, IN 

(180970078) 

Marion, IN 

(180970079) 

Marion, IN 

(180970081) 

Marion, IN 

(180970083) 

Tippecanoe, IN 

(181570008) 

Scott, IA 

(191630019) 

Jefferson, KY 

(211110043) 

Jefferson, KY 

(211110044) 

Jefferson, KY 

(211110048) 

Baltimore City, MD 

(245100040) 

Baltimore City, MD 

(245100049) 

Monroe, MI 

(261150005) 

Oakland, MI 

(261250001) 

St. Clair, MI 

(261470005) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630015) 

Wayne, MI 

(261630016) 

Wayne, MI 

(261630019) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Jefferson, MO 

(290990012) 

Saint Charles, MO 

(291831002) 

St. Louis City, MO 

(295100007) 

St. Louis City, MO 

(295100087) 

Hudson, NJ 

(340171003) 

Hudson, NJ 

(340172002) 

Union, NJ 

(340390004) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Butler, OH 

(390170003) 

Butler, OH 

(390170016) 

Butler, OH 

(390170017) 

Butler, OH 

(390171004) 

Cuyahoga, OH 

(390350038) 

Cuyahoga, OH 

(390350045) 

Cuyahoga, OH 

(390350060) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610006) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390610040) 

Hamilton, OH 

(390610042) 

Hamilton, OH 

(390610043) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Jefferson, OH 

(390811001) 

Montgomery, OH 

(391130032) 

Summit, OH 

(391530017) 

Montgomery, TN 

(471251009) 

Brooke, WV 

(540090011) 

Milwaukee, WI 

(550790026) 

Milwaukee, WI 

(550790043) 

Milwaukee, WI 

(550790099) 

Tennessee .................. 61 Jefferson, AL 

(10730023) 

Jefferson, AL 

(10732003) 

New Haven, CT 

(90091123) 

Madison, IL 

(171190023) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Clark, IN 

(180190006) 

Dubois, IN 

(180372001) 

Knox, IN 

(180830004) 

Marion, IN 

(180970042) 

Marion, IN 

(180970043) 

Marion, IN 

(180970066) 

Marion, IN 

(180970078) 

Marion, IN 

(180970079) 

Marion, IN 

(180970081) 

Marion, IN 

(180970083) 

Tippecanoe, IN 

(181570008) 

Scott, IA 

(191630019) 

Daviess, KY 

(210590005) 

Jefferson, KY 

(211110043) 

Jefferson, KY 

(211110044) 

Jefferson, KY 

(211110048) 

Monroe, MI 

(261150005) 

Oakland, MI 

(261250001) 

St. Clair, MI 

(261470005) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630015) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Jefferson, MO 

(290990012) 

Saint Charles, MO 

(291831002) 

St. Louis City, MO 

(295100007) 

St. Louis City, MO 

(295100087) 

Union, NJ 

(340390004) 

New York, NY 

(360610128) 

Butler, OH 

(390170003) 

Butler, OH 

(390170016) 

Butler, OH 

(390170017) 

Butler, OH 

(390171004) 

Cuyahoga, OH 

(390350038) 

Cuyahoga, OH 

(390350045) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610006) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390610040) 

Hamilton, OH 

(390610042) 

Hamilton, OH 

(390610043) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Jefferson, OH 

(390811001) 

Montgomery, OH 

(391130032) 

Summit, OH 

(391530017) 

Allegheny, PA 

(420030093) 

Allegheny, PA 

(420030116) 

Allegheny, PA 

(420031008) 

Allegheny, PA 

(420031301) 

Cambria, PA 

(420210011) 

York, PA 

(421330008) 

Virginia ....................... 13 New Haven, CT 

(90091123) 

Baltimore City, MD 

(245100040) 

Baltimore City, MD 

(245100049) 

Hudson, NJ 

(340171003) 

Hudson, NJ 

(340172002) 

Union, NJ 

(340390004) 


erowe on DSK5CLS3C1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45265 

TABLE IV.C–17—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued 

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Berks, PA 

(420110011) 

Dauphin, PA 

(420430401) 

Lancaster, PA 

(420710007) 

York, PA 

(421330008) 

West Virginia .............. 84 Jefferson, AL 

(10730023) 

Jefferson, AL 

(10732003) 

New Haven, CT 

(90091123) 

Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Madison, IL 

(171190023) 

Madison, IL 

(171191007) 

Madison, IL 

(171192009) 

Madison, IL 

(171193007) 

Clark, IN 

(180190006) 

Dubois, IN 

(180372001) 

Lake, IN 

(180890026) 

Marion, IN 

(180970042) 

Marion, IN 

(180970043) 

Marion, IN 

(180970066) 

Marion, IN 

(180970078) 

Marion, IN 

(180970079) 

Marion, IN 

(180970081) 

Marion, IN 

(180970083) 

Tippecanoe, IN 

(181570008) 

Scott, IA 

(191630019) 

Jefferson, KY 

(211110043) 

Jefferson, KY 

(211110044) 

Jefferson, KY 

(211110048) 

Baltimore City, MD 

(245100040) 

Baltimore City, MD 

(245100049) 

Monroe, MI 

(261150005) 

Oakland, MI 

(261250001) 

St. Clair, MI 

(261470005) 

Washtenaw, MI 

(261610008) 

Wayne, MI 

(261630015) 

Wayne, MI 

(261630016) 

Wayne, MI 

(261630019) 

Wayne, MI 

(261630033) 

Wayne, MI 

(261630036) 

Jefferson, MO 

(290990012) 

Saint Charles, MO 

(291831002) 

St. Louis City, MO 

(295100007) 

St. Louis City, MO 

(295100087) 

Hudson, NJ 

(340171003) 

Hudson, NJ 

(340172002) 

Union, NJ 

(340390004) 

Bronx, NY 

(360050080) 

New York, NY 

(360610056) 

New York, NY 

(360610128) 

Butler, OH 

(390170003) 

Butler, OH 

(390170016) 

Butler, OH 

(390170017) 

Butler, OH 

(390171004) 

Cuyahoga, OH 

(390350038) 

Cuyahoga, OH 

(390350045) 

Cuyahoga, OH 

(390350060) 

Cuyahoga, OH 

(390350065) 

Franklin, OH 

(390490024) 

Franklin, OH 

(390490025) 

Hamilton, OH 

(390610006) 

Hamilton, OH 

(390610014) 

Hamilton, OH 

(390610040) 

Hamilton, OH 

(390610042) 

Hamilton, OH 

(390610043) 

Hamilton, OH 

(390617001) 

Hamilton, OH 

(390618001) 

Jefferson, OH 

(390811001) 

Montgomery, OH 

(391130032) 

Summit, OH 

(391530017) 

Allegheny, PA 

(420030008) 

Allegheny, PA 

(420030064) 

Allegheny, PA 

(420030093) 

Allegheny, PA 

(420030116) 

Allegheny, PA 

(420031008) 

Allegheny, PA 

(420031301) 

Beaver, PA 

(420070014) 

Berks, PA 

(420110011) 

Cambria, PA 

(420210011) 

Dauphin, PA 

(420430401) 

Lancaster, PA 

(420710007) 

York, PA 

(421330008) 

Montgomery, TN 

(471251009) 

Milwaukee, WI 

(550790043) 

Wisconsin ................... 12 Cook, IL 

(170310052) 

Cook, IL 

(170310057) 

Cook, IL 

(170310076) 

Cook, IL 

(170311016) 

Cook, IL 

(170312001) 

Cook, IL 

(170313103) 

Cook, IL 

(170313301) 

Cook, IL 

(170316005) 

Lake, IN 

(180890022) 

Lake, IN 

(180890026) 

Scott, IA 

(191630019) 

Wayne, MI 

(261630016) 

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 nonattainment sites (monitoring site ID) 

Connecticut ................ 1 New York, NY 

(360610062) 

Delaware .................... 2 Cumberland, PA 

(420410101) 

New York, NY 

(360610079) 

Georgia ....................... 3 Baltimore City, MD 

(245100035) 

Lucas, OH 

(390950026) 

Preble, OH 

(391351001) 

Illinois ......................... 29 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Elkhart, IN 

(180390003) 

Floyd, IN 

(180431004) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Bullitt, KY 

(210290006) 

McCracken, KY 

(211451004) 

Warren, KY 

(212270007) 

Wayne, MI 

(261630001) 

St. Louis City, MO 

(295100085) 

New York, NY 

(360610079) 

Cuyahoga, OH 

(390350027) 

Cuyahoga, OH 

(390350034) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Mahoning, OH 

(390990014) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Trumbull, OH 

(391550007) 

Allegheny, PA 

(420030095) 

Allegheny, PA 

(420033007) 

Washington, PA 

(421255001) 

Sumner, TN 

(471650007) 

Brooke, WV 

(540090005) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Indiana ........................ 34 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Muscatine, IA 

(191390015) 

Bullitt, KY 

(210290006) 

McCracken, KY 

(211451004) 

Warren, KY 

(212270007) 

Anne Arundel, MD 

(240031003) 

Wayne, MI 

(261630001) 

St. Louis City, MO 

(295100085) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Cuyahoga, OH 

(390350027) 

Cuyahoga, OH 

(390350034) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Mahoning, OH 

(390990014) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Trumbull, OH 

(391550007) 

Allegheny, PA 

(420030095) 

Allegheny, PA 

(420033007) 

Cumberland, PA 

(420410101) 

Washington, PA 

(421255001) 

Sumner, TN 

(471650007) 

Brooke, WV 

(540090005) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Iowa ............................ 9 Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

St. Louis City, MO 

(295100085) 


erowe on DSK5CLS3C1PROD with PROPOSALS2
45266 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

TABLE IV.C–18—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued 

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Kansas ....................... 2 Muscatine, IA 

(191390015) 

Milwaukee, WI 

(550790059) 

Kentucky ..................... 33 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Floyd, IN 

(180431004) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Anne Arundel, MD 

(240031003) 

Wayne, MI 

(261630001) 

St. Louis City, MO 

(295100085) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Cuyahoga, OH 

(390350027) 

Cuyahoga, OH 

(390350034) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Mahoning, OH 

(390990014) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Trumbull, OH 

(391550007) 

Allegheny, PA 

(420030095) 

Allegheny, PA 

(420033007) 

Washington, PA 

(421255001) 

Sumner, TN 

(471650007) 

Brooke, WV 

(540090005) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Maryland ..................... 5 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Cumberland, PA 

(420410101) 

Massachusetts ........... 1 New York, NY 

(360610062) 

Michigan ..................... 28 District of Columbia 

(110010041) 

Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Warren, KY 

(212270007) 

St. Louis City, MO 

(295100085) 

Cuyahoga, OH 

(390350027) 

Cuyahoga, OH 

(390350034) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Mahoning, OH 

(390990014) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Trumbull, OH 

(391550007) 

Allegheny, PA 

(420030095) 

Allegheny, PA 

(420033007) 

Washington, PA 

(421255001) 

Sumner, TN 

(471650007) 

Brooke, WV 

(540090005) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Minnesota ................... 4 Muscatine, IA 

(191390015) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Missouri ...................... 20 Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Floyd, IN 

(180431004) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Bullitt, KY 

(210290006) 

McCracken, KY 

(211451004) 

Warren, KY 

(212270007) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950026) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Sumner, TN 

(471650007) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Nebraska .................... 2 Muscatine, IA 

(191390015) 

Milwaukee, WI 

(550790059) 

New Jersey ................ 5 District of Columbia 

(110010041) 

Anne Arundel, MD 

(240031003) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Cumberland, PA 

(420410101) 

New York .................... 9 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Anne Arundel, MD 

(240031003) 

Baltimore City, MD 

(245100035) 

Cuyahoga, OH 

(390350027) 

Cuyahoga, OH 

(390350034) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Cumberland, PA 

(420410101) 

North Carolina ............ 3 Baltimore City, MD 

(245100035) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Ohio ............................ 29 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Floyd, IN 

(180431004) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Bullitt, KY 

(210290006) 

McCracken, KY 

(211451004) 

Warren, KY 

(212270007) 

Anne Arundel, MD 

(240031003) 

Baltimore City, MD 

(245100035) 

Wayne, MI 

(261630001) 

St. Louis City, MO 

(295100085) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Allegheny, PA 

(420030095) 

Allegheny, PA 

(420033007) 

Cumberland, PA 

(420410101) 

Washington, PA 

(421255001) 

Sumner, TN 

(471650007) 

Brooke, WV 

(540090005) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Pennsylvania .............. 32 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Floyd, IN 

(180431004) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Bullitt, KY 

(210290006) 

Warren, KY 

(212270007) 

Anne Arundel, MD 

(240031003) 

Baltimore City, MD 

(245100035) 

Wayne, MI 

(261630001) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Cuyahoga, OH 

(390350027) 

Cuyahoga, OH 

(390350034) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Mahoning, OH 

(390990014) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Trumbull, OH 

(391550007) 

Sumner, TN 

(471650007) 

Brooke, WV 

(540090005) 

Dane, WI 

(550250047) 


erowe on DSK5CLS3C1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 45267 

53For 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. 

TABLE IV.C–18—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued 

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Tennessee .................. 21 Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Floyd, IN 

(180431004) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Bullitt, KY 

(210290006) 

McCracken, KY 

(211451004) 

Warren, KY 

(212270007) 

Wayne, MI 

(261630001) 

St. Louis City, MO 

(295100085) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Mahoning, OH 

(390990014) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Trumbull, OH 

(391550007) 

Allegheny, PA 

(420033007) 

Washington, PA 

(421255001) 

Virginia ....................... 7 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Anne Arundel, MD 

(240031003) 

Baltimore City, MD 

(245100035) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Cumberland, PA 

(420410101) 

West Virginia .............. 35 District of Columbia 

(110010041) 

District of Columbia 

(110010042) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Saint Clair, IL 

(171630010) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Floyd, IN 

(180431004) 

Vigo, IN 

(181670023) 

Muscatine, IA 

(191390015) 

Bullitt, KY 

(210290006) 

Warren, KY 

(212270007) 

Anne Arundel, MD 

(240031003) 

Baltimore City, MD 

(245100035) 

Wayne, MI 

(261630001) 

St. Louis City, MO 

(295100085) 

New York, NY 

(360610062) 

New York, NY 

(360610079) 

Cuyahoga, OH 

(390350027) 

Cuyahoga, OH 

(390350034) 

Jefferson, OH 

(390810017) 

Lucas, OH 

(390950024) 

Lucas, OH 

(390950026) 

Mahoning, OH 

(390990014) 

Montgomery, OH 

(391130031) 

Preble, OH 

(391351001) 

Trumbull, OH 

(391550007) 

Allegheny, PA 

(420030095) 

Allegheny, PA 

(420033007) 

Cumberland, PA 

(420410101) 

Washington, PA 

(421255001) 

Sumner, TN 

(471650007) 

Dane, WI 

(550250047) 

Milwaukee, WI 

(550790059) 

Waukesha, WI 

(551330027) 

Wisconsin ................... 6 Cook, IL 

(170310022) 

Cook, IL 

(170310050) 

Cook, IL 

(170314007) 

Will, IL 

(171971002) 

Elkhart, IN 

(180390003) 

Muscatine, IA 

(191390015) 

b. Results of 8-Hour Ozone Contribution 

Modeling 

In this section, we present the 

interstate contributions from emissions 

in upwind states to downwind 

nonattainment and maintenance sites 

for the ozone NAAQS. As described 

previously in section IV.B., states which 

contribute 0.8 ppb or more to 8-hour 

ozone nonattainment or maintenance in 

another state are identified as states 

with contributions to downwind 

attainment and maintenance sites large 

enough to warrant further analysis. We 

performed air quality modeling to 

quantify the contributions to 8-hour 

ozone from emissions in each of the 

following 37 states individually: 

Alabama, Arkansas, Connecticut, 

Delaware, Florida, Georgia, Illinois, 

Indiana, Iowa, Kansas, Kentucky, 

Louisiana, Maine, Maryland combined 

with the District of Columbia, 

Massachusetts, Michigan, Minnesota, 

Mississippi, Missouri, Nebraska, New 

Hampshire, New Jersey, New York, 

North Carolina, North Dakota, Ohio, 

Oklahoma, Pennsylvania, Rhode Island, 

South Carolina, South Dakota, 

Tennessee, Texas, Vermont, Virginia, 

West Virginia, and Wisconsin. 

We calculated each state’s 

contribution to each of the 11 

monitoring sites that are projected to be 

nonattainment and each of 14 53 sites 

that are projected to have maintenance 

problems for the 8-hour ozone NAAQS 

in the 2012 Base Case. The largest 

contribution from each state to 8-hour 

ozone nonattainment in downwind sites 

is provided in Table IV.C–19. The 

largest contribution from each state to 8- 

hour ozone maintenance in downwind 

sites is also provided in Table IV.C–19. 

The contributions from each state to all 

projected 2012 nonattainment and 

maintenance sites for the 8-hour ozone 

NAAQS are provided in the AQMTSD. 

TABLE IV.C–19—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH

OF 37 STATES

Upwind State 

Largest downwind contribution to nonattainment for 

ozone 

(ppb) 

Largest downwind contribution to maintenance for 

ozone 

(ppb) 

Alabama ................................................................................................................................................................... 4.7 4.7 

Arkansas .................................................................................................................................................................. 1.4 1.8 

Connecticut .............................................................................................................................................................. 1.7 1.6 

Delaware .................................................................................................................................................................. 3.3 2.5 

Florida ...................................................................................................................................................................... 0.8 2.1 

Georgia .................................................................................................................................................................... 2.1 1.7 


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54As 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. 

TABLE IV.C–19—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH

OF 37 STATES—Continued 

Upwind State 

Largest downwind contribution to nonattainment for 

ozone 

(ppb) 

Largest downwind contribution to maintenance for 

ozone 

(ppb) 

Illinois ....................................................................................................................................................................... 0.8 0.6 

Indiana ..................................................................................................................................................................... 1.1 1.0 

Iowa ......................................................................................................................................................................... 0.3 0.3 

Kansas ..................................................................................................................................................................... 0.6 0.8 

Kentucky .................................................................................................................................................................. 2.3 1.8 

Louisiana .................................................................................................................................................................. 11.4 10.6 

Maine ....................................................................................................................................................................... 0.0 0.0 

Maryland/Washington, DC ....................................................................................................................................... 6.1 4.2 

Massachusetts ......................................................................................................................................................... 0.6 0.5 

Michigan ................................................................................................................................................................... 0.9 0.5 

Minnesota ................................................................................................................................................................ 0.1 0.2 

Mississippi ................................................................................................................................................................ 5.2 2.5 

Missouri .................................................................................................................................................................... 0.7 0.6 

Nebraska .................................................................................................................................................................. 0.2 0.2 

New Hampshire ....................................................................................................................................................... 0.1 0.1 

New Jersey .............................................................................................................................................................. 16.8 15.8 

New York ................................................................................................................................................................. 0.4 22.7 

North Carolina .......................................................................................................................................................... 1.7 2.0 

North Dakota ............................................................................................................................................................ 0.1 0.0 

Ohio ......................................................................................................................................................................... 2.8 2.6 

Oklahoma ................................................................................................................................................................. 2.1 2.7 

Pennsylvania ............................................................................................................................................................ 8.9 8.1 

Rhode Island ............................................................................................................................................................ 0.1 0.1 

South Carolina ......................................................................................................................................................... 0.6 0.8 

South Dakota ........................................................................................................................................................... 0.0 0.0 

Tennessee ............................................................................................................................................................... 1.6 3.0 

Texas ....................................................................................................................................................................... 1.6 0.6 

Vermont ................................................................................................................................................................... 0.0 0.1 

Virginia ..................................................................................................................................................................... 4.2 4.5 

West Virginia ............................................................................................................................................................ 2.7 2.3 

Wisconsin ................................................................................................................................................................. 0.3 0.2 

Based on the state-by-state 

contribution analysis, there are 22 states 

and the District of Columbia 54 which 

contribute 0.8 ppb or more to 

downwind 8-hour ozone nonattainment. 

These states are: Alabama, Arkansas, 

Connecticut, Delaware, the District of 

Columbia, Florida, Georgia, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Mississippi, New 

Jersey, North Carolina, Ohio, Oklahoma, 

Pennsylvania, Tennessee, Texas, 

Virginia, and West Virginia. In Table 

IV.C–20, we provide a list of the 

downwind nonattainment counties to 

which each upwind state contributes 0.8 

ppb or more (i.e., the upwind state to 

downwind nonattainment ‘‘linkages’’). 

There are 22 states and the District of 

Columbia which contribute 0.8 ppb or 

more to downwind 8-hour ozone 

maintenance. These states are: Alabama, 

Arkansas, Connecticut, Delaware, the 

District of Columbia, Florida, Georgia, 

Indiana, Kansas, Kentucky, Louisiana, 

Maryland, Mississippi, New Jersey, New 

York, North Carolina, Ohio, Oklahoma, 

Pennsylvania, South Carolina, 

Tennessee, Virginia, and West Virginia. 

In Table IV.C–21, we provide a list of 

the downwind nonattainment counties 

to which each upwind state contributes 

0.8 ppb or more (i.e., the upwind state 

to downwind nonattainment ‘‘linkages’’). 

TABLE IV.C–20—UPWIND STATE TO DOWNWIND NONATTAINMENT ‘‘LINKAGES’’ FOR 8-HOUR OZONE

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Alabama ..................... 8 East Baton Rouge, 

LA 

(220330003) 

Brazoria, TX 

(480391004) 

Harris, TX 

(482010051) 

Harris, TX 

(482010055) 

Harris, TX 

(482010062) 

Harris, TX 

(482010066) 

Harris, TX 

(482011039) 

Tarrant, TX 

(484391002) 

Arkansas .................... 3 East Baton Rouge, 

LA 

(220330003) 

Brazoria, TX 

(480391004) 

Tarrant, TX 

(484391002) 


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TABLE IV.C–20—UPWIND STATE TO DOWNWIND NONATTAINMENT ‘‘LINKAGES’’ FOR 8-HOUR OZONE—Continued 

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Connecticut ................ 1 Suffolk, NY 

(361030009) 

Delaware .................... 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

Florida ........................ 2 Harris, TX 

(482010062) 

Tarrant, TX 

(484391002) 

Georgia ....................... 7 Brazoria, TX 

(480391004) 

Harris, TX 

(482010051) 

Harris, TX 

(482010055) 

Harris, TX 

(482010062) 

Harris, TX 

(482010066) 

Harris, TX 

(482011039) 

Tarrant, TX 

(484391002) 

Illinois ......................... 2 Suffolk, NY 

(361030009) 

Harris, TX 

(482010055) 

Indiana ........................ 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

Kentucky ..................... 6 Suffolk, NY 

(361030002) 

Philadelphia, PA 

(421010024) 

Harris, TX 

(482010051) 

Harris, TX 

(482010055) 

Harris, TX 

(482010062) 

Harris, TX 

(482011039) 

Louisiana .................... 7 Brazoria, TX 

(480391004) 

Harris, TX 

(482010051) 

Harris, TX 

(482010055) 

Harris, TX 

(482010062) 

Harris, TX 

(482010066) 

Harris, TX 

(482011039) 

Tarrant, TX 

(484391002) 

Maryland ..................... 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

Michigan ..................... 1 Suffolk, NY 

(361030009) 

Mississippi .................. 8 East Baton Rouge, 

LA 

(220330003) 

Brazoria, TX 

(480391004) 

Harris, TX 

(482010051) 

Harris, TX 

(482010055) 

Harris, TX 

(482010062) 

Harris, TX 

(482010066) 

Harris, TX 

(482011039) 

Tarrant, TX 

(484391002) 

New Jersey ................ 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

North Carolina ............ 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

Ohio ............................ 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

Oklahoma ................... 1 Tarrant, TX 

(484391002) 

Pennsylvania .............. 2 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Tennessee .................. 7 Philadelphia, PA 

(421010024) 

Brazoria, TX 

(480391004) 

Harris, TX 

(482010051) 

Harris, TX 

(482010055) 

Harris, TX 

(482010062) 

Harris, TX 

(482010066) 

Harris, TX 

(482011039) 

Texas .......................... 1 East Baton Rouge, 

LA 

(220330003) 

Virginia ....................... 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

West Virginia .............. 3 Suffolk, NY 

(361030002) 

Suffolk, NY 

(361030009) 

Philadelphia, PA 

(421010024) 

TABLE IV.C–21—UPWIND STATE TO DOWNWIND MAINTENANCE ‘‘LINKAGES’’ FOR 8-HOUR OZONE

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Alabama ..................... 6 DeKalb, GA 

(130890002) 

Fulton, GA 

(131210055) 

Harris, TX 

(482010024) 

Harris, TX 

(482010029) 

Harris, TX 

(482011050) 

Tarrant, TX. 

(484392003). 

Arkansas .................... 4 Dallas, TX 

(481130069) 

Dallas, TX 

(481130087) 

Harris, TX 

(482011050) 

Tarrant, TX 

(484392003) 

Connecticut ................ 1 Westchester, NY 

(361192004) 

Delaware .................... 1 Bucks, PA 

(420170012) 

Florida ........................ 4 DeKalb, GA 

(130890002) 

Fulton, GA 

(131210055) 

Harris, TX 

(482010024) 

Harris, TX 

(482010029) 

Georgia ....................... 4 Harris, TX 

(482010024) 

Harris, TX 

(482010029) 

Harris, TX 

(482011050) 

Tarrant, TX 

(484392003) 

Indiana ........................ 4 Fairfield, CT 

(90010017) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA 

(420170012) 

Kansas ....................... 1 Dallas, TX 

(481130069) 

Kentucky ..................... 6 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA. 

(420170012). 


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TABLE IV.C–21—UPWIND STATE TO DOWNWIND MAINTENANCE ‘‘LINKAGES’’ FOR 8-HOUR OZONE—Continued 

Upwind State Number of 

linkages 

Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID) 

Louisiana .................... 6 Dallas, TX 

(481130069) 

Dallas, TX 

(481130087) 

Harris, TX 

(482010024) 

Harris, TX 

(482010029) 

Harris, TX 

(482011050) 

Tarrant, TX. 

(484392003). 

Maryland ..................... 6 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA. 

(420170012). 

Mississippi .................. 7 DeKalb, GA 

(130890002) 

Fulton, GA 

(131210055) 

Dallas, TX 

(481130087) 

Harris, TX 

(482010024) 

Harris, TX 

(482010029) 

Harris, TX. 

(482011050). 

Tarrant, TX 

(484392003) 

New Jersey ................ 6 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA. 

(420170012). 

New York .................... 5 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Bucks, PA 

(420170012) 

North Carolina ............ 5 Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA 

(420170012) 

Ohio ............................ 6 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA. 

(420170012). 

Oklahoma ................... 3 Dallas, TX 

(481130069) 

Dallas, TX 

(481130087) 

Tarrant, TX 

(484392003) 

Pennsylvania .............. 5 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

South Carolina ........... 2 Fulton, GA 

(131210055) 

Harris, TX 

(482010029) 

Tennessee .................. 5 DeKalb, GA 

(130890002) 

Fulton, GA 

(131210055) 

Bucks, PA 

(420170012) 

Harris, TX 

(482010024) 

Harris, TX 

(482011050) 

Virginia ....................... 6 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA. 

(420170012). 

West Virginia .............. 6 Fairfield, CT 

(90010017) 

Fairfield, CT 

(90011123) 

Fairfield, CT 

(90013007) 

New Haven, CT 

(90093002) 

Westchester, NY 

(361192004) 

Bucks, PA. 

(420170012). 

D. Proposed Methodology To Quantify 

Emissions That Significantly Contribute 

or Interfere With Maintenance 

In this section, EPA explains its 

general approach to quantifying the 

amount of emissions that represent 

significant contribution and interference 

with maintenance. EPA then applies 

that approach for the three different 

NAAQS being addressed in today’s 

notice: The 1997 ozone NAAQS, the 

1997 annual 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 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 PM2.5

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 

PM2.5 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 

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 


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methodology relied upon defining 

significant contribution as those 

emissions that could be removed with 

the use of ‘‘highly cost effective’’ 

controls. In this action, rather than 

relying solely on determining 

reductions based on ‘‘highly cost 

effective’’ controls, EPA uses a number 

of factors that account for both cost and 

air quality improvement. Furthermore, 

unlike the 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 DC Circuit Court’s 

determination that EPA may consider 

cost when measuring significant 

contribution, Michigan, 213 F.3d at 679, 

and its rejection of the manner in which 

cost was used in the CAIR analysis, 

North Carolina, 531 F.3d at 917. It also 

recognizes that the Court accepted—but 

did not require—EPA’s use of a single, 

uniform cost threshold to measure 

significant contribution. Michigan, 213 

F.3d at 679. 

The methodology defines each state’s 

significant contribution and interference 

with maintenance as the emissions that 

can be eliminated for a specific cost. 

Unlike the 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 from EGUs 

in each state at those thresholds, and 

consider the impact of variability in 

EGU operations. 

In step one, EPA identifies what 

emissions reductions are available at 

various costs, quantifying emissions 

reductions that would occur within 

each state at ascending costs per ton of 

emissions reductions. For purposes of 

this discussion, we refer to these as 

‘‘cost curves’’. 

In step two, EPA uses an air quality 

assessment tool to estimate the impact 

that the combined reductions available 

from upwind contributing states and the 

downwind state, at different cost-perton levels, would have on air quality at 

downwind monitor sites that had 

nonattainment and/or maintenance 

problems. 

In step three, EPA examines cost and 

air quality information to identify cost 

‘‘breakpoints.’’ Breakpoints are the 

places where there is a noticeable 

change on one of the cost curves, such 

as a point where a large reduction 

occurs because a certain type of 

emissions control becomes costeffective. EPA then uses a multi-factor 

assessment to determine the amount of 

emissions that represents significant 

contribution to nonattainment and 

interference with maintenance. The 

factors considered include both the air 

quality and cost considerations used in 

developing the breakpoints along with 

additional air quality and cost 

considerations. This assessment is 

performed for each transported NAAQS 

pollutant or precursor which EPA has 

concluded must be regulated due to its 

impact on downwind receptors. In this 

rule, as discussed in section IV.B, EPA 

is proposing to regulate 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 have 

already done a great deal to reduce 

emissions while the downwind state in 

which the nonattainment area is located 

has done very little. Conversely, the 

downwind state may have made large 

reductions while one or more 

contributing upwind states may have 

done very little. There may be cases 

where some states (upwind or 

downwind) have large emissions (and a 

correspondingly large impact 

downwind) not because their sources 

are poorly controlled, but because they 

have a greater number of sources—the 

operation of which is critical to the 

reliability of the electric grid. 

Conversely, there may be cases where a 

state (upwind or downwind) contributes 

less in total emissions because it has a 

smaller number of plants, but those 

plants are poorly controlled and could 

be better controlled at a relatively low 

cost. 

Air quality factors alone are not able 

to discern these types of differences. 

Using both air quality and cost factors 

allows EPA to consider the full range of 

circumstances and state-specific factors 

that affect the relationship between 

upwind emissions and downwind 

nonattainment and maintenance 

problems. For example, considering cost 

takes into account the extent to which 

existing plants are already controlled as 

well as the potential for, and relative 

difficulty of, additional emissions 

reductions. Therefore, EPA believes that 

it is appropriate to consider both cost 

and air quality metrics when 

quantifying each state’s significant 

contribution. 

This methodology is consistent with 

the statutory mandate in section 

110(a)(2)(D)(i)(I) which requires upwind 

states to prohibit emissions that 

significantly contribute to 

nonattainment or interfere with 

maintenance in another state, but does 

not shift the responsibility for achieving 

or maintaining the NAAQS to the 

upwind state. 

In developing and implementing this 

methodology, EPA was cognizant of a 

number of factors. First, in many areas, 

transported emissions are a key 

component of the downwind air quality 

problem. Second, there are large 

amounts of low cost emission reduction 

opportunities in upwind states. Third, 

EPA recognizes that section 110(a)(2)(D) 

does not grant EPA authority to require 

emissions reductions solely because 

they provide large health and 

environmental benefits: reductions 

required pursuant to section 

110(a)(2)(D)(i)(I) must be related to the 

goal of eliminating upwind state 

emissions that significantly contribute 

to nonattainment or interfere with 

maintenance of the NAAQS in 

downwind areas. 

Fourth, EPA is cognizant of the 

relationship between the upwind and 

downwind state requirements in the 

Act. The Act requires upwind states to 

eliminate significant interstate pollution 

transport under section 110(a)(2)(D). It 

also requires each state to assure 

attainment and maintenance of the 

NAAQS within its borders. Thus, a 

downwind state must adopt controls to 

demonstrate timely attainment of the 

NAAQS despite any pollution transport 

from upwind states that is not 

eliminated under section 110(a)(2)(D). 


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55We also recognize that there can be reasons to 

depart from an equal cost per ton allocation of 

responsibility before a receptor’s attainment and 

maintenance problem is fully resolved, such as 

when a receptor’s air quality problem has an 

unusually high local component. 

Given this structure, interpreting 

significant contribution and interfere 

with maintenance inherently involves a 

policy decision on how much emissions 

control responsibility should be 

assigned to upwind states, and how 

much responsibility should be left to 

downwind states. In virtually all areas, 

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 necessary for the 

downwind state to obtain deeper 

pollution reductions to attain and 

maintain air quality standards, which 

increases costs of control in the 

downwind state. Fourth, from the 

standpoint of a downwind state, the 

pollution contribution of each upwind 

state adds up to a larger, cumulative 

degradation of the downwind state’s air 

quality. Fifth, reducing interstate 

pollution enhances prospects that 

attainment in downwind states can be 

achieved within the Act’s deadlines and 

as expeditiously as practicable. All of 

these points support the position that 

upwind state sources should bear 

substantial responsibility to control 

their emissions. 

On the other hand, the proposed 

methodology ensures that upwind states 

are not required to shoulder the entire 

responsibility for the downwind state’s 

attainment and maintenance of the 

NAAQS. Among other things, our 

methodology implicitly assumes 

controls at the same cost per ton level 

in the downwind state as in the upwind 

contributing states.55 In addition, in 

almost all cases, states with downwind 

nonattainment and maintenance areas 

are also required to reduce emissions 

based on the fact that they are also 

upwind states that are ‘‘linked’’ to other 

downwind states with nonattainment 

and maintenance problems. 

The proposed methodology also 

directly ties each state’s reduction 

requirements to EPA’s analysis of that 

state’s significant contribution and 

interference with maintenance. The 

required reductions would provide very 

substantial air quality improvements. 

For the annual 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 for EGUs in a state. In other 

words, EPA determined for specific cost 

per ton thresholds, the emissions 

reductions that would be achieved in a 

state if all EGUs in that state used all 

emission controls and emission 

reduction measures available at that cost 

threshold. The zero point of the curve 

shows what emissions would occur 

absent any additional investment in 

emissions reductions (i.e., the base case 

emissions). Additional points on the 

curves show the emissions that would 

occur after the installation of all 

controls that could be installed at 

specific cost levels (dollars per ton of 

emissions reduced). In developing these 

cost curves, EPA used IPM to identify 

costs for reducing emissions from EGUs 

by modeling emissions reductions 

available at multiple cost increments. 

EPA also applied the same cost 

constraint for each state in each 

modeling iteration. For example, in one 

iteration, all covered sources in the 

states examined were constrained to 

emit at levels achievable by the 

application of all controls available for 

$100/ton. In a second iteration, all states 

examined were assumed to achieve all 

reductions in each state that were 

available at $200/ton. The resulting cost 

curves for 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, ‘‘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 reexamined non-EGUs to determine the 

accuracy of its initial assumptions that 

there were little or no reductions 

available from non-EGUs at costs lower 

than the thresholds that EPA had 

chosen. EPA’s analysis of the costs of 

and opportunities for non-EGU 

emissions reductions is discussed in 

more detail in section IV.D.3, later. For 

the reasons explained in that section, 

EPA believes there are little or no nonEGU reductions available at the cost 

thresholds used in this rule. Therefore, 

EPA believes it is reasonable at this time 

to use cost curves that include only EGU 

reductions. However, EPA is continuing 

to conduct analyses and believes that it 

will be necessary to further consider 

non-EGU emission reduction 

opportunities in future transport rules. 

To develop cost curves, emissions 

available at various costs were assessed 

in 2012 for ozone season 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 


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56As is discussed in the RIA, EPA also used the 

CAMx model to perform air quality analysis of its 

proposed remedy to address significant 

contribution. Results from this modeling will not 

exactly correspond to results from the air quality 

tool both because the inputs to the air quality 

modeling are different and the sophisticated model 

more fully accounts for the complex air chemistry 

interactions. The full air quality modeling looks at 

the remedy, including reductions in upwind states 

that do not contribute as well as the impacts of the 

variability provisions discussed later in this section. 

It also provides a metric against which to evaluate 

the air quality assessment tool. 

time. This is true because, among other 

things, control options that are available 

in a longer timeframe may not be 

available in a shorter timeframe. For 

instance, it takes approximately 27 

months to build a flue gas 

desulfurization unit (FGD, or 

‘‘scrubber’’) to reduce 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 

Installation Timing, USEPA, March 

2005). 

There are approximately 30 months 

between mid-2011 (when the Agency 

anticipates finalizing this rule) and 

January 2014 (the proposed Phase 2 

compliance deadline). EPA believes this 

is sufficient time for sources to install 

the advanced emissions controls 

projected to be retrofit. EPA expects 

about 14 GW of FGD and less than 1 GW 

of SCR capacity to be retrofit for Phase 

2 of this rule. This is significantly less 

than the capacity that was retrofit in the 

same length of time after CAIR was 

finalized. EPA is not aware of problems 

or issues with sources meeting the CAIR 

compliance deadlines, either in 

equipment deliveries or labor 

availability. EPA believes the proposed 

Transport Rule compliance deadlines 

are reasonable, and will result in 

emissions reductions as quickly as 

practicable, delivering health benefits to 

the public and aiding states with 

NAAQS attainment deadlines. 

EPA requests comment on the 

schedule for scrubber and SCR 

installations, the availability of 

boilermaker labor, and any comment on 

whether there might be alternative postcombustion cost-effective technologies 

that could reduce SO2 and/or NOX

emissions. We also solicit comment on 

whether advanced coal preparation 

processes might provide emissions 

reductions at the significant 

contribution cost levels identified in 

this proposal, whether such processes 

have been commercialized, and what 

the costs will be. In addition, EPA seeks 

comment on, whether other factors, 

such as other EPA regulatory actions, 

will create an increase in boilermaker 

demand earlier than today’s proposal, in 

2010 and beyond. We solicit comments 

on whether other factors might increase 

demand for boilermakers or control 

equipment, and what these factors 

would be. Comments in support of or 

opposed to the proposed compliance 

deadlines should include information to 

support the commenter’s position. 

Unlike add-on pollution controls such 

as scrubbers and SCRs, EPA believes 

that low-NOX burners could be installed 

by 2012. See TSD, ‘‘Installation Timing 

for Low NOX Burners,’’ in the docket for 

this rule. 

EPA also believes that sources can 

switch coals by 2012. Eastern 

bituminous coals used for power 

generation typically have more than 

sufficient sulfur content to facilitate 

highly efficient collection of fly ash in 

a cold-side electrostatic precipitator 

(ESP). Some ESPs that operate at 

acceptably high collection efficiency 

when using a high-or medium-sulfur 

bituminous coal may experience some 

loss in collection efficiency when a 

lower sulfur coal is used. Whether this 

occurs on a specific unit, and the extent 

to which it occurs, would depend on the 

design margins built into the existing 

ESP, the percentage change in coal 

sulfur content, and other factors. 

Relatively inexpensive practices to 

maintain high ESP performance on 

lower sulfur bituminous coals are 

available and are being used 

successfully where necessary. These 

include a range of upgrades to ESP 

components and flue gas conditioning. 

EPA assumes in the Transport Rule 

analysis that it will not be necessary for 

units that switch from higher to lower 

sulfur bituminous to make a costly 

replacement of the ESP. EPA’s analysis 

therefore does not add capital or 

operations and maintenance costs for 

coal switching from higher to lower 

sulfur bituminous coals. 

EPA’s analysis does not allow a unit 

designed for bituminous to switch to 

(very low sulfur) subbituminous coal 

unless the unit has demonstrated that 

capability in the past. EPA assumes 

units with that capability have already 

made any investments needed to handle 

a switch to subbituminous coals. EPA 

therefore assumes that any modeled coal 

switching from bituminous to 

subbituminous has no cost or schedule 

impact. 

EPA requests comment on the 

reasonableness of EPA’s assumption 

that coal switching within the 

bituminous coal grades will have 

relatively little cost or schedule impact 

on most units. 

b. Step 2. Performing the Air Quality 

Assessment 

In the second step, EPA uses an air 

quality assessment tool to estimate the 

impact of the upwind emissions 

reductions on downwind ambient 

concentrations.56 This tool is useful for 

identifying cost breakpoints for 

significant improvements in downwind 

air quality changes, including estimated 

effects on downwind attainment. While 

less rigorous than the air quality models 

used for attainment demonstrations, 

EPA believes this air quality assessment 

tool is acceptable for assessing the 

impact of numerous options on upwind 

reductions in the process of identifying 

upwind state significant contribution. It 

allows the Agency to analyze many 

more potential scenarios than the timeand resource-intensive more refined air 

quality modeling would permit. This 

tool assesses the impact that reductions 

at a given cost breakpoint from all of the 

contributing states (as well as the state 

with the nonattainment area itself) had 

on pollutant concentrations at that 

downwind area. The resulting 

information is used in step three. For 

each downwind area with a 

nonattainment and/or maintenance 

problem, it shows the total 

improvement in air quality for each cost 

level and associated pollutant 

reduction, the amount of the remaining 

problem caused by each upwind state 

(by constituent), and the amount of the 

remaining problem caused by sources 

within the state (by constituent). It also 

shows, overall, how much of the 

downwind air quality problem had been 

addressed at different cost levels. More 

detail on the tool itself, what EPA has 

done to verify the underlying 

assumptions, and the specific 

application of the tool to examining 

significant contribution for ozone and 

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 multifactor assessment to identify which cost 


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57The cost thresholds identified in today’s 

proposal are specific to the section 110(a)(2)(D) 

requirements for the states and NAAQS considered 

in this proposal. They do not represent an agency 

position on the appropriateness of such cost 

thresholds for any other application under the Act. 

threshold 57 or thresholds should be 

used to quantify states’ significant 

contribution and interference with 

maintenance. This new methodology 

responds to the Court’s statements in 

North Carolina v. EPA both criticizing 

the manner in which cost was used in 

the CAIR rule and acknowledging its 

prior acceptance (in Michigan v. EPA, 

213 F.3d 663) of EPA’s use of a uniform 

cost threshold and the uniform control 

requirements associated with the use of 

such a cost threshold. See North 

Carolina v. EPA, 531 F.3d at 908, 

917.920. In both the 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 emissions reductions cost curves 

developed in steps 1 and 2 related to 

(1) air quality (e.g., points at which all 

areas (other than those with an 

unusually predominant local pollution 

problem) reach attainment and have 

maintenance fully addressed), and/or (2) 

cost (e.g., points at which significant 

reductions are available because a 

certain technology is widely deployed). 

EPA identifies potential breakpoints and 

then uses a multi-factor assessment to 

evaluate whether one or more of the 

potential breakpoints represent a 

reasonable cost at which to define 

significant contribution for some or all 

upwind states. The factors in this multifactor assessment can be divided into 

two broad categories: Those that focus 

on air quality considerations and those 

that focus on cost considerations. Air 

quality considerations include, for 

example, how much air quality 

improvement in downwind states 

results from upwind state emissions 

reductions at different levels; whether, 

considering upwind emissions 

reductions and assumed local (in-state) 

reductions, the downwind air quality 

problems would be resolved; and the 

components of the remaining 

downwind air quality problem (e.g., is 

it a predominantly local or in-state 

problem, or does it still contain a large 

upwind component). Cost 

considerations include, for example, 

how the cost per ton compares with the 

cost per ton of existing federal and state 

rules for the same pollutant, and 

whether the cost per ton is consistent 

with the cost per ton of technologies 

already widely deployed (similar to the 

highly-cost-effective criteria used in 

both the 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 shortterm solution and then switch to 

another long-term solution (e.g., 

switching coals can involve plant 

modifications. While these costs are low 

when amortized over a number of years, 

if a source quickly installs controls, and 

switches coals again, costs may be 

higher than projected). 

Because upwind state sources should 

bear substantial responsibility for 

controlling emissions that contribute to 

air quality degradation in downwind 

states, EPA believes that cost per ton 

levels that are consistent with widely 

deployed existing controls, or are within 

the cost per ton range of controls 

already required by existing and 

proposed Federal and State rules (i.e., 

similar to the highly cost effective 

concept in the 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 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 stateby-state basis, the amount of emissions 

that could be reduced at a specific cost. 

The results of this analysis are used to 

develop the state budgets and variability 

limits, which are in turn used to 

implement the requirements to 

eliminate significant contribution and 

interference with maintenance. See 

sections IV.E and IV.F. 

2. Application 

The discussion that follows explains 

how the methodology described 

previously was applied to quantify 

significant contribution with respect to 

the 1997 and 2006 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 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. 


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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 

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 less. For SO2, the projected cost 

considered for reducing a ton of 

emissions 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 

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 


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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 

during the ozone season. 

The cost curves demonstrate that 

many of these sources would operate 

their SCR units when emissions 

reductions that cost $500/ton are 

required. In addition, at this $500/ton 

level some additional units would likely 

install advanced combustion control 

technology. Below $500/ton, there are 

very few other 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 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 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). 

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 

(3) Step 2. Air Quality Assessment of 

Potential Emissions Reductions 

After developing cost curves to show 

the state-by-state cost-effective 

emissions reductions available, EPA 

used the air quality assessment tool to 

evaluate the impact these upwind 

reductions would have on air quality in 

‘‘linked’’ downwind nonattainment and 

maintenance areas. This section 

summarizes the results of that 

evaluation and provides analysis that 

informs EPA’s multi-factor assessment, 

explained in step 3, later. 

EPA performed air quality analysis for 

each downwind receptor with a 

nonattainment and/or maintenance 

problem. For each receptor, EPA 

assessed the air quality improvement 

resulting when a group of states, 

consisting of the upwind states that are 

‘‘linked’’ to the downwind receptor (i.e., 

EPA modeling showed that they 

exceeded the one percent contribution 

threshold, based on it’s 2012 linkage 

analysis), and the downwind state 

where the receptor is located, all made 

the emissions reductions that EPA 

identified as available at each cost 

threshold (as described previously). 

This analysis did not assume any 

reductions in upwind states covered by 

this rule but not ‘‘linked’’ to the 

downwind receptor (even if the state 

was ‘‘linked’’ to a different receptor), 

beyond those assumed in the base case. 

The percent emissions reductions 

(and percent air quality improvement) 


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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. 

Figures IV.D–1 through IV.D–4 show 

that at increased costs, there are 

substantial increased emissions 

reductions. As explained previously, 

each decrease in emissions is assumed 

to lead to a corresponding improvement 

in downwind air quality. These changes 

apply to both the daily and annual 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). 


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58Measured 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. 

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 

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. 

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] 

Marginal cost per ton 

2014 2014 

Number of remaining nonattainment 

monitor sites 

Number of remaining nonattainment and 

maintenance 

monitor sites 

>$0 ........................................................................................................................................................................... 12 19 

>$100 ....................................................................................................................................................................... 3 6 

>$200 ....................................................................................................................................................................... 2 3 

>$300 ....................................................................................................................................................................... 2 3 

>$400 ....................................................................................................................................................................... 1 2 

>$500 ....................................................................................................................................................................... 1 2 

>$600 ....................................................................................................................................................................... 1 1 

>$800 ....................................................................................................................................................................... 1 1 

>$1,000 .................................................................................................................................................................... 1 1 

>$1,200 .................................................................................................................................................................... 1 1 

>$1,400 .................................................................................................................................................................... 1 1 

>$1,600 .................................................................................................................................................................... 1 1 

>$1,800 .................................................................................................................................................................... 0 1 

>$2,000 .................................................................................................................................................................... 0 1 

>$2,400 .................................................................................................................................................................... 0 1 

TABLE IV.D–4—DAILY AIR QUALITY IMPACTS VS. SO2 COST PER TON LEVELS IN 2014 

Marginal SO2 cost per ton 

Number of 

remaining 

nonattainment and 

maintenance monitor sites 

Air quality improvement (average μg/ 

m∧3 Reduction) 

relative to 2014 base case (zero dollars/ 

ton) 

All sites in 

2012 base 

6 selected 

sites * 

3 selected 

sites ** 

>$0 ................................................................................................................................... 64 0.0 0.0 0.0 

>$100 ............................................................................................................................... 16 3.7 2.0 1.8 

>$200 ............................................................................................................................... 12 4.4 2.4 2.1 

>$300 ............................................................................................................................... 8 4.7 2.6 2.3 

>$400 ............................................................................................................................... * 6 5.0 2.9 2.6 

>$500 ............................................................................................................................... 6 5.1 3.0 2.6 

>$600 ............................................................................................................................... 6 5.3 3.1 2.8 

>$800 ............................................................................................................................... 6 5.4 3.3 2.9 

>$1,000 ............................................................................................................................ 6 5.6 3.4 3.0 

>$1,200 ............................................................................................................................ 6 5.7 3.4 3.0 

>$1,400 ............................................................................................................................ 6 5.8 3.5 3.1 

>$1,600 ............................................................................................................................ 5 6.0 3.6 3.2 

>$1,800 ............................................................................................................................ 4 6.2 3.7 3.3 

>$2,000 ............................................................................................................................ ** 3 6.4 3.9 3.4 

>$2,400 ............................................................................................................................ 1 6.8 4.1 3.7 

* The six sites are: Allegheny County, PA (2 sites); Baltimore County, MD; Wayne County, MI; Lake County, IN; Cook County, IL. 

** The three sites are: Lake County, IN; Cook County, IL; Allegheny County, PA. 

A number of conclusions can be 

drawn from Tables IV.D–3 and IV.D–4. 

Very low cost SO2 reductions result in 

significant air quality benefits.58 As 

explained previously, this is because 

there are significant reductions available 

from sources that operate existing 

scrubbers and, in a number of cases, use 

relatively low cost, lower sulfur coal. At 

the same time, in 2014 enough lead time 

exists for considerable emission 

reduction opportunities from new 

scrubber installations. Other programs 

are also achieving reductions (for 

example, some state rules and 

enforcement consent decrees require 

SO2 and NOX reductions in 2013 and 

2014). The analysis also shows that 

higher cost reductions continue to 

provide downwind air quality 

improvements. 


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59When considering all reductions made, 

including those by states that contribute less than 

1 percent, the air quality assessment tool projects 

that both nonattainment and maintenance will be 

fully addressed in all areas except for Allegheny 

County, PA at $2,000/ton. 

(4) Identifying Cost Thresholds 

(a) Considerations for 2014 

For 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 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 15), EPA 

believes that it is clearly possible for the 

power sector to install at least that 

quantity of scrubbers by 2014. The 

$2,400/ton 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 more than 1 percent.59 As is 

explained later in this section, EPA 

believes that the monitor in Allegheny 

County that remains in nonattainment is 

in an area where the air quality problem 

is primarily local. Since EPA’s analysis 

suggests that the only remaining 

nonattainment problem is primarily 

local, EPA did not consider higher cost 

thresholds. 

EPA did not consider additional cost 

thresholds for 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; 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 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 

area is significantly affected by a large 

increment of local emissions from a 

sizable coke production facility and 

other nearby sources. (See http:// 

www.epa.gov/pmdesignations/ 

2006standards/final/TSD/ 

tsd_4.0_4.3_4.3.3_r03_PA_2.pdf). High 

concentrations of organic carbon 

indicate the unique local problem for 

this location. 

Because the remaining 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 could be reduced for 

$2,000/ton in 2014 is an appropriate 

quantification of a state’s significant 

contribution, EPA considered whether 

any of these emissions reductions could 

be achieved prior to 2014. For the 

reasons that follow, EPA concluded that 

significant reductions could be achieved 

by 2012 and that it is important to 

require all such reductions by 2012 to 

ensure that they are achieved as 

expeditiously as practicable. While EPA 

believes that it is not possible to require 

the installation of post-combustion SO2

controls (scrubbers) or post-combustion 

NOX 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, 


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consistent with the Act’s requirement 

that downwind states attain the NAAQS 

as expeditiously as practicable. Section 

IV.E explains how these 2012 emissions 

reductions requirements are defined. 

(c) Off-Ramp for States That Eliminate 

Their Significant Contribution for Less 

Than $2,000/Ton 

Table IV.D.4, previously, shows that 

for large numbers of monitoring sites 

where there are nonattainment and or 

maintenance problems, those problems 

are fully resolved before all states 

achieve all of the emissions reductions 

that could be achieved at or below 

$2,000/ton. EPA used the air quality 

assessment tool to analyze the impact of 

requiring all states linked to the 

downwind state site with an air quality 

problem, as well as the downwind state, 

to reduce emissions consistent with the 

levels discussed for 2012 in section 

IV.D.2.a(2), previously. The air quality 

assessment tool shows that those 2012 

reductions will resolve the 

nonattainment and maintenance 

problems for all of the areas to which 

the following states are linked: 

Alabama, Connecticut, Delaware, the 

District of Columbia, Florida, Kansas, 

Louisiana, Maryland, Massachusetts, 

Minnesota, Nebraska, New Jersey and 

South Carolina (referred to as group 2 

states). EPA also assessed whether, in 

2014, the combination of this level of 

reduction from the group 2 states and 

the remaining states (referred to as 

group 1 states) continued to result in all 

downwind areas—except for Allegheny 

County, Pennsylvania—fully addressing 

their nonattainment and or/maintenance 

problems, and determined that it did. 

The states in group 1 and group 2 are 

rationally grouped considering air 

quality and cost. EPA proposes that it 

would not be appropriate to assign the 

same cost per ton to group 2 and group 

1 states because a significantly lower 

cost per ton was sufficient to resolve air 

quality problems at all downwind 

receptors linked to the group 2 states. 

Although states are linked to different 

sets of downwind receptors, our 

analysis indicated that the cost per ton 

needed to resolve downwind air quality 

problems varied only to a limited extent 

among states within group 1 and among 

states within group 2. The cost per ton 

did vary greatly between the group 1 

and group 2 states. Limitations on the 

accuracy of our cost and air quality 

analyses, and the ruling in the Michigan 

decision accepting EPA’s prior use of a 

uniform cost approach, support the 

decision to use uniform costs for a 

group of states. 

(d) Proposed Cost Thresholds for PM2.5

Summary of methodology. In 

summary, EPA determined that SO2

emissions that could be reduced for 

$2,000/ton in 2014 should be 

considered a state’s significant 

contribution, unless EPA determined 

that a lesser reduction would fully 

resolve the nonattainment and/or 

maintenance problem for all the 

downwind monitoring sites to which a 

particular state might be linked. For 

these ‘‘group 2 states’’ EPA is 

determining that a lesser reduction of 

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 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 

$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 ....................................................................................................................................... ........................ X X 

Connecticut .................................................................................................................................. ........................ X X 

Delaware ...................................................................................................................................... ........................ X X 

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

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

Georgia ........................................................................................................................................ X ........................ X 

Illinois ........................................................................................................................................... X ........................ X 

Indiana ......................................................................................................................................... X ........................ X 

Iowa ............................................................................................................................................. X ........................ X 

Kansas ......................................................................................................................................... ........................ X X 

Kentucky ...................................................................................................................................... X ........................ X 

Louisiana ...................................................................................................................................... ........................ X X 

Maryland ...................................................................................................................................... ........................ X X 

Massachusetts ............................................................................................................................. ........................ X X 

Michigan ....................................................................................................................................... X ........................ X 

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

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

Nebraska ...................................................................................................................................... ........................ X X 

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

New York ..................................................................................................................................... X ........................ X 

North Carolina .............................................................................................................................. X ........................ X 

Ohio ............................................................................................................................................. X ........................ X 

Pennsylvania ................................................................................................................................ X ........................ X 

South Carolina ............................................................................................................................. ........................ X X 

Tennessee ................................................................................................................................... X ........................ X 

Virginia ......................................................................................................................................... X ........................ X 

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

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

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


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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 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 

nonattainment and that Birmingham, 

AL would exceed the threshold for 

‘‘maintenance’’ by a slight amount (less 

than 0.1 ug/m 3). Given the unique local 

nature of the Allegheny County, PA 

receptor (see discussion previously), 

EPA does not believe that the fact that 

the air quality assessment tool projects 

the area to have only a maintenance 

problem, while the refined air quality 

modeling suggests that the area would 

remain in nonattainment, raises any 

serious issues about the conclusions 

regarding significant contribution to 

nonattainment and interference with 

maintenance with the annual 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 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 

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 emissions than for 

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. 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 


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60While Colorado is also a state that may see 

projected increases in emissions, it was not within 

the domain the EPA analyzed. 

maintenance problems after the 

implementation of the 2012 reductions. 

EPA also notes that during the winter, 

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 whether 

there should be a higher cost threshold 

for annual nitrogen oxides. This may be 

appropriate for states that have been 

identified as contributing significantly 

to sites that the CAMx air quality 

modeling continues to show as having 

a residual nonattainment and/or 

maintenance concern in 2014. 

Finally, EPA requests comment on 

how and whether EPA should 

incorporate the use of detailed models 

such as CAMx into our methodology for 

significant contribution and interference 

with maintenance. 

(g) Possibility for Emissions Increases in 

Noncontributing States 

EPA also evaluated whether the 

proposed rule could cause changes in 

operation of electric generating units in 

states not regulated under the proposal 

(that is states not listed in table IV.D– 

5). Specifically, EPA evaluated whether 

such changes could lead to increases in 

emissions in those states, potentially 

affecting whether they would exceed the 

1 percent contribution thresholds used 

to identify linkages between upwind 

and downwind states. (See sections IV.B 

and IV.C previously for more discussion 

of the 1 percent thresholds). Such 

changes are possible in part because of 

the interconnected nature of the 

country’s energy system (including both 

the electricity grid and coal and natural 

gas supplies). In addition, our models 

project that the rule affects the cost of 

coal (generally lowering the cost of 

higher sulfur coals and raising the cost 

of lower sulfur coals). If these price 

effects took place and if the rule is 

finalized as proposed, sources in states 

not covered by the proposed rule might 

choose to use higher sulfur coals. 

Increased use of such coals could thus 

increase 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 

tons.60 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 

tons) 

Arkansas .................................................................................................................................................................. 32 127 

Mississippi ................................................................................................................................................................ 18 80 

North Dakota ............................................................................................................................................................ 11 94 

South Dakota ........................................................................................................................................................... 6 26 

Texas ....................................................................................................................................................................... 136 640 

Further analysis with the air quality 

assessment tool indicates that these 

projected increases in the Texas 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, 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 interference 

with maintenance for states that 


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61This is possible where: (1) Latest monitoring 

data indicate attainment of the 1997 ozone 

standard, (2) the area is operating under one-year 

extensions of their 2009 deadline, or (3) EPA has 

not made a formal finding of failure to attain. 

62 In the case of 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. 

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 emissions 

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 

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 emissions reductions 

would likely involve placing reduction 

requirements on sources other than 

EGUs and that additional approaches 

would need to be addressed. EPA 

believes that developing supplemental 

information to address these sources 

and concepts would substantially delay 

publication of a final rule, beyond the 

anticipated publication of spring 2011. 

EPA plans to move forward 

aggressively in the event that these 

further reductions are needed. We do 

not, however, intend to delay the 

reductions in this proposed rule because 

those reductions have a substantial 

impact on states’ abilities to attain the 

NAAQS in the required time period and 

have large health benefits. 

b. Specific Application to Ozone 

This section discusses, for the 1997 

ozone standards, how EPA applies its 

multi-step methodology for defining 

each state’s significant contribution. For 

some aspects of the methodology, 

further work is needed to complete the 

methodology for ozone and this further 

work will be completed in a separate 

proposal. 

(1) Years for Quantifying Significant 

Contribution 

In this subsection, we discuss how 

EPA identifies for ozone the years to 

analyze for eliminating significant 

contribution. Similar to the previous 

discussion for 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 

any states ‘‘linked’’ to ‘‘serious area’’ 

locations for which 2012 is the latest 

ozone season prior to their attainment 

deadline, EPA believes that 2012 is the 

appropriate year for eliminating 

significant contribution, to the extent 

that purpose can be achieved given the 

short time period. Because this 

proposed rule would not be finalized 

until 2011, the year 2012 also represents 

the earliest time by which emissions 

reductions could be achieved, which is 

consistent with statutory provisions 

calling for downwind states to achieve 

attainment ‘‘as expeditiously as 

practicable.’’ This also is relevant for 

certain other areas with lower ozone 

classifications that are projected in our 

analysis to have continuing air quality 

problems and to be affected by 

transported pollution from certain 

upwind states in amounts greater than 

the 1 percent threshold.61

EPA is concerned that the timing of 

this rule presents difficult challenges in 

eliminating significant contribution and 

interference with maintenance with 

regard to the 1997 ozone NAAQS by the 

attainment date. For states with a 2012 

(or earlier) attainment date for which we 

project continuing ozone problems, we 

are concerned that strict adherence to a 

2012 date for reductions could be 

viewed as an artificial constraint on our 

ability to require appropriate 

reductions. EPA believes that the 

current situation for ozone, involving a 

transport rulemaking within months of 

the attainment date (and in a number of 

cases, after the current attainment date) 

is a unique situation created by the 

Court’s remand of the CAIR. Under 

normal circumstances adhering to the 

CAA schedule for addressing transport 

within 3 years after a NAAQS is 

promulgated, transport requirements 

would be in place years before the 

attainment date. For purposes of our 

analysis of ozone for areas with a 2012 

attainment date, EPA proposes that we 

should not be constrained to only 

considering those reductions that are 

possible by 2012. 

Another reason that it would be 

inappropriate to limit upwind state 

responsibility based on the downwind 

area’s current attainment date is that the 

statute contains provisions for extension 

of attainment dates. To the extent that 

downwind states have continuing ozone 

air quality problems after 2012, the Act 

requires that they be reclassified, which 

allows the downwind area to qualify for 

a later attainment date that is as 

expeditious as practicable but no later 

than 2019 (2018 emissions year).62 In 

addition, two 1-year attainment date 

extensions can be granted if an area 

comes close to attaining, based on 

specific criteria. In addition, history 

shows many examples of states not 

meeting air quality standards by their 

attainment deadlines, often due in part 

to interstate pollution transport. Even if 

a downwind area attains on time, 

further upwind reductions may be 

important to assure continued 

maintenance of the standard. 

If in determining upwind state 

reduction responsibilities EPA were to 

automatically assume that downwind 

states will attain on time despite 

pollution transport, this assumption 

would have the effect of absolving the 

upwind state of responsibility for any 

reductions in pollution transport that 

could not be achieved by the downwind 

area’s current attainment date. EPA does 

not believe this would be appropriate. 

This would transfer emissions control 

responsibility from the upwind state to 

the downwind state in any case when 

the area did not attain by its current 

attainment date, and could delay for 

years the date when the public would 

breathe air that meets health-based 

standards. 

Accordingly, for all the reasons 

discussed previously, we address both 

2012 and 2014 in our analysis, and we 

do not believe that examining 2012 only 

would be appropriate. EPA has chosen 

to examine 2014 air quality results 

because, based on a conservative 

estimate, 2014 is the earliest year for 

which significantly more stringent 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, 


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63Estimate from EPA report, ‘‘Engineering and 

Economic Factors Affecting the Installation of 

Control Technologies for Multi-Pollutant Strategies,’’ CAIR docket no. OAR–2003–0053– 

0106). 

is classified as ‘‘severe.’’ For Houston, it 

is relevant to consider both that (1) the 

latest permissible attainment date for 

severe areas is June 2019, which would 

require emissions reductions by the 

2018 ozone season, and (2) the state 

implementation plan must provide for 

attainment as expeditiously as 

practicable. In light of this, EPA may 

select a year between 2012 and 2018 

that is as expeditious as practicable as 

the appropriate year for eliminating 

significant contribution. Because, as 

explained later, further analysis is 

needed to quantify any additional 

reductions necessary to eliminate 

significant contribution to Houston, 

EPA requests comment on which year 

we should select within this 2012 to 

2018 time period for this analysis. 

(2) Step 1. Emissions Reductions Cost 

Curves for EGU Ozone Season 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 addon equipment. Some highly effective 

and widely employed NOX control 

technologies such as SCR could not be 

planned and installed in significant 

numbers within a 1-year time period 

(i.e., because a single SCR unit on 

average takes 21 months to install,63

SCR-based limits in 2012, if feasible at 

all, would require an unacceptably steep 

cost premium). 

For some states (particularly those 

which are not regulated by the 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 

Maryland ........................................................................... 14 14 14 14 14 14 14 14 14 

Michigan ........................................................................... 30 30 30 30 30 30 29 28 28 

Mississippi ........................................................................ 17 8 8 8 8 8 8 8 8 

New Jersey ...................................................................... 7 7 7 7 7 7 7 7 7 

New York .......................................................................... 16 16 16 16 16 16 16 16 16 

North Carolina .................................................................. 27 27 27 27 27 27 27 27 27 

Ohio .................................................................................. 42 41 41 41 41 42 42 42 42 

Oklahoma ......................................................................... 43 27 27 27 27 26 26 26 26 

Pennsylvania .................................................................... 51 51 51 51 50 50 50 50 48 

South Carolina ................................................................. 16 16 16 15 15 15 15 15 15 

Tennessee ....................................................................... 12 12 12 12 12 12 12 12 12 

Texas ............................................................................... 79 67 67 67 7 66 66 66 66 

Virginia ............................................................................. 18 18 18 18 18 18 17 17 17 

West Virginia .................................................................... 24 24 23 23 22 23 22 22 18 

Total .......................................................................... 746 648 632 628 625 622 620 618 609 

As discussed in section IV.D.3 later, 

little or no ozone season NOX

reductions are available for non-EGU 

sources from control measures costing 

(at or below) $500/ton. The ozone 

season NOX cost curves in Table IV.D– 

7 include EGU reductions only. EPA 

believes that for costs at or below $500/ 

ton, these curves include all available 

reductions (because only EGUs have 

substantial reduction opportunities at or 

below $500/ton), but for greater costs 

the curves do not include all available 

reductions as they do not include nonEGU reductions. 

For this reason, we are not addressing 

in this proposal whether cost per ton 

levels higher than $500/ton are justified 

for some upwind states and downwind 

receptors for ozone purposes. However, 

we are presenting the information we 

have on potential EGU reductions at 

higher cost levels for informational 

purposes. EPA intends to develop 

similar emissions reductions and cost 

information for sources other than EGUs 

and, in a future rulemaking, to consider 

whether or not reductions at a higher 

cost per ton are warranted for EGUs and 

other source categories. 

EPA developed EGU emissions 

reductions cost curves for 2014 as well 

as 2012. EPA believes it is useful to 

understand and display emissions 

reductions capabilities for 2014, the first 

year for which further emissions 

reductions could be achieved through 

the installation of add-on controls such 

as SCR. These 2014 ozone season 


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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 

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 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. 

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 

Marginal Cost per Ton 

Number of Remaining Nonattainment 

Monitor Sites 

Number of Remaining Nonattainment and 

Maintenance 

Monitor Sites 

Number of Remaining Nonattainment Monitor Sites 

Number of Remaining Nonattainment and Maintenance Monitor 

sites 

>$0 .................................................. 11 25 4 (all in Houston, TX) ..................... 7 (Houston, TX; Baton Rouge, LA). 

>$500 .............................................. 10 19 1 ..................................................... 7. 


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(4) Step 3. Selection of Cost Thresholds, 

Taking Into Account Cost and Air 

Quality Considerations 

Using the multi-factor cost and air 

quality methodology described in 

section IV.D.1, EPA identifies, for a 

number of states, the 2012 emissions 

reductions that eliminate the significant 

contribution to nonattainment of the 

1997 ozone NAAQS and interference 

with maintenance to the 1997 ozone 

NAAQS. 

(a) Cost Considerations 

As discussed previously, $500/ton 

represents the cost level for which EPA 

has complete information across source 

categories and represents the level for 

which significant emissions reductions 

are available in 2012. Large additional 

reductions in 2012 cannot be achieved 

given the insufficient amount of time for 

sources to install controls. Compared to 

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 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. Thus, EPA 

believes that additional post-2012 

controls, beyond the $500/ton 

reductions that are justified based on 

2012, are possibly warranted for states 

that are linked to Houston and Baton 

Rouge. (See also discussion later on the 

issue regarding New York City raised by 

air quality modeling results.) 

(c) Proposed Cost Threshold for Ozone 

Based on the cost and air quality 

considerations, EPA proposes $500/ton 

as the appropriate cost threshold for the 

following states which contribute to 

downwind nonattainment and/or 

maintenance problems in 2012, but 

which are not linked to ozone air 

quality problems in either Houston or 

Baton Rouge: Connecticut, Delaware, 

the District of Columbia, Indiana, Iowa, 

Kansas, Maryland, Massachusetts, New 

Jersey, New York, North Carolina, Ohio, 

Oklahoma, Pennsylvania, South 

Carolina, Virginia, and West Virginia. 

For states linked to ozone air quality 

problems in Houston or Baton Rouge, 

EPA has not yet identified a cost 

threshold for eliminating significant 

contribution. EPA does, however, 

propose to find that those states must 

make at least all of the reductions that 

can be achieved for $500/ton in 2012. 

These states are: Alabama, Arkansas, 

Florida, Georgia, Illinois, Kentucky, 

Louisiana, Mississippi, Tennessee, and 

Texas. For these states, the $500/ton 

threshold represents emissions 

reductions that EPA believes are an 

essential part of the ultimate emissions 

reductions amount that will be required 

to eliminate the significant contribution 

and interference with maintenance. This 

level does not represent a complete 

significant contribution determination 

for these states because neither the 

analysis of costs up to $500/ton, nor the 

analysis of air quality impacts of the 

corresponding emissions reductions, 

suggest that those reductions necessarily 

represent all reasonable upwind state 

reductions. For the reasons stated 

previously in subsection 2.b, EPA 

believes it is appropriate and consistent 

with the statutory mandate to consider 

whether section 110(a)(2)(D)(i)(I) 

requires further reductions from these 

states after 2012 for purposes of the 

1997 ozone standard. 

To determine whether further 

reductions are warranted, EPA is 

expeditiously conducting further 

analysis. EPA is continuing to develop 

and evaluate 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 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 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 


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64 Identification and Discussion of Sources of 

Regional Point Source NOX and SO2 emissions 

other than EGUs. EPA/OAQPS and CAMD. January 

2004. 

65Reference: 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. 

66U.S. EPA. Petroleum Refinery National Priority 

Case Results. Available at http://www.epa.gov/

compliance/resources/cases/civil/caa/oil/index.

html. 

67U.S. EPA. Acid Plant NSR Enforcement 

Priority. Available at http://www.epa.gov/ 

compliance/civil/caa/acidplant-nsr/index.html. 

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 (at or below) $500/ton. The modeling 

also showed that the locations within 

the New York City nonattainment area 

would continue to have a maintenance 

problem despite the modeled reductions 

(including those in New York State). 

That is, the New York City area is 

possibly at risk of being in 

nonattainment in light of historical yearto-year variability in ozone levels in the 

New York City area. For that reason, 

EPA is taking comment on whether it 

should consider and analyze the 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 

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 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 $2,000/ton 

or less (in year 2006 $). 

For the CAIR, EPA included a 

technical support document 64 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 highestemitting 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. 

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 NESCAUM 65 suggests scrubber costs 

are typically well above $2,000/ton for 

ICI boilers. 

For Portland cement manufacturing, 

information from a 2006 report prepared 

by the Lake Michigan Air Directors 

Consortium (LADCO) estimated costs 

for SO2 scrubbing to be between $2,211– 

6,917 per ton (in year 2003 $). The 

LADCO ‘‘white papers’’ discussion is 

available from the following Web site: 

http://www.ladco.org/reports/control/

final_reports/identification_and_

evaluation_of_candidate_control_

measures_ii_june_2006.pdf. 

For petroleum refining, the largest 

sources of 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 at or 

below $2,000/ton will generally not be 

available at refineries covered by the 

recent settlement agreements EPA has 

entered into with numerous petroleum 

refineries. Moreover, such agreements 

cover 88 percent of U.S refining 

capacity, and will lead to up to 250,000 

tons of 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.66

For sulfuric acid manufacturing, the 

SO2 emissions are related to the percent 

recovery of sulfuric acid product. 

Because the percent recovery is plantspecific, the available emissions 

reductions and the cost per ton of 

controls are highly variable. At the time 

of the CAIR, EPA made rough 

calculations that the then-existing 

126,000 tons of 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.67 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 


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

68 Identification and Discussion of Sources of 

Regional Point Source NOX and SO2 emissions 

other than EGUs. EPA/OAQPS and CAMD. January 

2004. 

69Reference: Identification and Evaluation of 

Candidate Control Measures. Phase II Final Report. 

LADCO, June. 2006. Appendix B. 

70Reference: Assessment of Control Technology 

Options For Petroleum Refineries in the MidAtlantic Region. Final Report. MARAMA, January 

2007. p. 2–24. 

71Reference: 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. 

72Reference: Identification and Evaluation of 

Candidate Control Measures. Phase II Final Report. 

LADCO, June 2006. Appendix B. 

73Even though allowance prices dropped 

significantly in 2008 after the Court decision, most 

sources appear to have continued with the same 

reduction strategies. 

control measures that would serve as 

the basis for those reductions. 

Because sulfur content of both 

gasoline and diesel fuel are now subject 

to very stringent sulfur requirements, 

EPA believes there are no available onroad and nonroad engine measures to 

reduce mobile source SO2 at or 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 

document 68 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 of non-EGU NOX controls 

done for the CAIR with a review of the 

year 2012 inventory. See TSD—‘‘NonEGU Emissions Reductions Cost and 

Potential.’’ The highest-emitting 

stationary source categories of non-EGU 

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 information 69 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 refineries, 70 glass 

manufacturing plants, and asphalt 

manufacturing plants. For industrial 

boilers, a recent report prepared by 

NESCAUM 71 suggests NOX control 

costs are typically well above $500/ton 

for ICI boilers. In addition, a recent 

report prepared by LADCO 72 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 or below $500/ton. 

EPA has not identified further 

controls for stationary nonpoint sources 

or mobile source NOX measures that 

have costs at or below $500 per ton. 

E. State Emissions Budgets 

As described later, EPA used the cost 

thresholds identified for each covered 

state in the previous section and applied 

them to state-specific data to develop 

individual state emissions budgets. 

These budgets facilitate implementation 

of the requirement that significant 

contribution and interference with 

maintenance be eliminated. A state’s 

emissions budget is the quantity of 

emissions that would remain in that 

state from covered sources after 

elimination of that portion of each 

state’s significant contribution and 

interference with maintenance that EPA 

has identified in today’s proposal, 

before accounting for the inherent 

variability in power system operations 

(see discussion of variability in section 

IV.F, later). The state emissions budget 

is a mechanism for converting the 

quantity of emissions that a state must 

reduce (i.e., the state’s significant 

contribution and interference with 

maintenance) into enforceable control 

requirements. In other words, it 

provides a quantity of emissions to use 

in developing a remedy (e.g., the 

remedy should be designed to achieve 

the budget in an average year). 

Because the budget represents 

emissions that would remain without 

accounting for variability, it also 

represents the amount of emissions that 

would remain after significant 

contribution and interference with 

maintenance have been addressed, in an 

average year. In a year when base case 

emissions would have been higher than 

average (e.g., because a large nuclear 

unit was out of service and more fossilfuel-fired generation was needed), the 

emissions that would remain after 

significant contribution and interference 

with maintenance had been addressed 

also would be higher. The variability 

limits discussed in section IV.F address 

this issue. Application of variability 

limits in the remedies is described in 

section V.D. 

1. Defining SO2 and Annual NOX State 

Emissions Budgets for EGUs 

For group 1 states required to make 

deeper emissions reductions in 2014, 

EPA based each state’s 2014 budgets on 

the same projections from IPM that were 

used as inputs into the cost curves 

explained in section IV.D.2.a 

previously. For SO2, the values were 

taken from an IPM run requiring all SO2

reductions available at $2,000/ton. For 

group 2 states (and for the first phase 

2012 budgets for sources required to 

make greater reductions in 2014), EPA 

took a different approach. These states 

are only required to make 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 covered by this rule in 2009,73

EPA believes that the actual 

performance units achieved in 2009 is 

more representative of expected 

emissions than what EPA modeled 

using IPM. This is because real data 

takes into account actual unit by unit 

information that is represented at a 

more aggregate level in IPM. The only 

exception to this rule is if a source was 

modeled to install a scrubber by 2012 

(because of rules requiring that 

installation and/or because of 

information that the company had 

already contracted to install a scrubber). 

In this case, EPA adjusted emissions 

from the unit to account for the new 

scrubber. 

For 2012 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 


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74The impact of variability on the budgets is 

discussed in section IV.F, later. 

represents reductions from turning on 

SCR units. EPA believes that instead of 

defining the budgets based on IPM 

projections of what will happen when 

SCR units are turned on, it is better to 

use real data, therefore EPA has 

developed budgets based on a 

combination of historical heat input, 

historical emissions rates, and, where 

new SCR units are expected between 

now and 2012, projected emissions rates 

for those new SCR units. The emissions 

budgets developed using the previous 

methodology are as follows in Table 

IV.E–1: 

TABLE IV.E–1—SO2 AND ANNUAL NOX STATE EMISSIONS BUDGETS FOR ELECTRIC GENERATING UNITS BEFORE

ACCOUNTING FOR VARIABILITY 74

[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 

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 

TABLE IV.E–2—OZONE-SEASON NOX

STATE EMISSIONS BUDGETS FOR

ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY—Continued 

[Tons] 

State 

NOX ozone 

season, all 

years 

Connecticut ............................... 1,315 

Delaware ................................... 2,450 

District of Columbia .................. 105 

Florida ....................................... 56,939 

Georgia ..................................... 32,144 

Illinois ........................................ 23,570 

Indiana ...................................... 49,987 

Kansas ...................................... 21,433 

Kentucky ................................... 30,908 

Louisiana .................................. 21,220 

Maryland ................................... 7,232 

Michigan ................................... 28,253 

Mississippi ................................ 16,530 

New Jersey ............................... 5,269 

New York .................................. 11,090 

North Carolina .......................... 23,539 

Ohio .......................................... 40,661 

TABLE IV.E–2—OZONE-SEASON NOX

STATE EMISSIONS BUDGETS FOR

ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY—Continued 

[Tons] 

State 

NOX ozone 

season, all 

years 

Oklahoma ................................. 37,087 

Pennsylvania ............................ 48,271 

South Carolina .......................... 15,222 

Tennessee ................................ 11,575 

Texas ........................................ 75,574 

Virginia ...................................... 12,608 

West Virginia ............................ 22,234 

Total ................................... 641,614 

These budgets are based on a 5 month 

ozone season (May 1 through September 

30). Consistent with the approach taken 

by the OTAG, the NOX SIP Call, and the 

CAIR, we propose to define the ozone 

season, for purposes of emissions 


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reductions requirements in this rule, as 

May through September. We recognize 

that this ozone season for regulatory 

requirements will have differences from 

the official state-specific ozone 

monitoring season. EPA requests 

comment on whether the budgets for the 

final rule should be based on a longer 

ozone season, such as March through 

October. 

F. Emission Reduction Requirements 

Including Variability 

In this section, EPA discusses the 

inherent variability in electric power 

system operation and presents proposed 

variability limits for each state. As 

explained below, EPA proposes to 

calculate variability limits for each state 

and to use those variability limits in 

conjunction with the budgets (which are 

based on expected average conditions) 

to provide limited flexibility (within the 

limits allowed by the variability 

provisions) to address years in which 

more fossil generation occurs than 

projected in the average base case year. 

This section also presents projected 

emission reduction results. 

1. Variability 

a. Introduction to Power Sector 

Variability 

Historically, power sector emissions 

have varied over time. Factors, such as 

fuel switching and installing new 

emissions controls, which can lead to 

significant decreases in emissions, 

primarily affect emissions rates rather 

than generation and change largely as a 

result of pollution regulation. 

Even when emissions rates do not 

change from year to year, overall 

emissions can change because of factors 

including power demand, timing of 

maintenance activities, and unexpected 

shutdowns of units. Extreme weather 

conditions, sudden economic shocks, 

and other unpredictable events can also 

significantly impact power generation 

from fossil units. These factors relate 

directly to heat input, generation, and 

the routine operation of power plants to 

supply our electricity, and thus affect 

total emissions. 

As discussed previously, EPA has 

identified a specific amount of 

emissions that must be prohibited by 

each state to satisfy the requirements of 

CAA section 110(a)(2)(D)(i)(I). EPA has 

also developed state budgets based on 

its projections of state emissions in an 

average year after the elimination of 

such emissions. However, because of 

the unavoidable variability in baseline 

emissions—resulting from the inherent 

variability in power plant operations— 

state-level emissions may vary 

somewhat after all significant 

contribution and interference with 

maintenance that EPA has identified in 

this proposal are eliminated. This 

occurs even when the emissions rates of 

the units within the state do not change. 

For this reason, EPA has determined 

that it is appropriate to develop 

variability limits for each state budget. 

These limits are used to identify the 

range of emissions that EPA believes 

may occur in each state following the 

elimination of all significant 

contribution and interference with 

maintenance. 

For the proposed rule, EPA proposes 

to factor this variability explicitly in its 

consideration of how to control 

emissions. The Agency believes that 

because baseline emissions are variable, 

emissions after the elimination of all 

significant contribution are also variable 

and thus it is appropriate to take this 

variability into account. 

As discussed in detail in section V, 

EPA proposes and considers specific 

regulatory remedies that are designed to 

meet the emissions budget in an average 

year. Because base case emissions may 

vary from projections, EPA believes 

these same remedies may incorporate 

provisions that account for variability. 

This variability, however, must be 

limited to provide downwind states 

with assurance that necessary 

reductions will be made in upwind 

states. This section describes how EPA 

calculated variability limits for each 

state to achieve this goal. 

Remedies (i.e., regulatory approaches 

for achieving emissions reductions) can 

range from emissions rate-based ‘‘direct 

control’’ options to options which allow 

for interstate trading. EPA believes that 

inherent variability in power system 

operations affects each state’s baseline 

emissions and thus also affects a state’s 

emissions after elimination of all 

significant contribution and interference 

with maintenance. Thus, emissions may 

vary somewhat after implementation of 

the remedies under consideration. 

Under an emissions rate-based 

approach, emissions rate limits could be 

developed that would meet the budget 

assuming a given pattern of operation 

for the affected units. If some of the 

units with higher emissions rates 

actually operated more than projected, 

the state’s actual emissions would be 

higher. In an interstate trading program, 

budgets could be developed that each 

state would be projected to meet in an 

average year. In some years, however, 

generation from units in one state may 

increase (with a corresponding increase 

in emissions), but because variability in 

a larger region is less significant than 

within a single state, the increase in one 

state would be expected to be offset by 

decreases in other states. Finally, even 

in an intrastate-only trading program, 

the ability to bank allowances could 

mean that in one year, emissions would 

be below the budget, while in another 

year they would be above. 

In all these cases, variability limits 

can be used to retain the flexibilities 

that the various remedies provide to 

deal with real-world variability in the 

operating system, while still providing 

downwind states reasonable certainty 

about the level of upwind emissions. 

EPA also notes that explicit 

consideration of variability in the 

emissions resulting from a remedy is 

consistent with removing a state’s 

‘‘significant contribution.’’ As noted 

previously, even if the emissions result 

is variable from year to year, there is 

still a similar increment of emissions 

reductions. For example, because 

increased emissions in the control case 

would also correspond to increased 

emissions in the base case, the 

increment of emissions representing 

significant contribution and interference 

with maintenance would still be 

removed. Finally, as is explained more 

below in IV.F.b, the variability limits (as 

applied, for instance, in the State 

Budgets/Limited Trading remedy in 

section V.D.4) are relatively low and 

thus the total amount of variability 

allowed is very small compared to total 

EGU emissions and even smaller when 

considering all of the emissions within 

a state. It is also worth noting that in the 

proposed State Budgets/Limited Trading 

remedy, variability is taken into account 

in such a way that does not allow an 

overall increase in emissions. Under 

this remedy, an individual state could 

emit up to its budget plus variability 

limit. However, the requirement that all 

sources hold allowances to cover 

emissions, and the fact that those 

allowances are allocated based on statespecific budgets absent variability, 

would ensure that total emissions do 

not increase. This remedy, therefore, 

ensures not only that total emissions do 

not increase above state budgets, but 

also that reductions occur in each and 

every state. 

b. How EPA Accounted for Inherent 

Power Sector Variability 

EPA determined 1-year variability 

limits and 3-year rolling average 

variability limits for each state. First, 

EPA determined 1-year variability limits 

based on historical variability in heat 

input. Second, EPA determined 3-year 

rolling average variability limits using 

statistical methods to convert the 1-year 

variability into 3-year variability. The 

approaches EPA used to determine the 


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75The two-tailed 95th percent confidence level is 

the equivalent of the 97.5th upper (single-tailed) 

confidence level. 

76Moore, David S. and George P. McCabe. 

Introduction to the Practice of Statistics. 2nd ed. 

New York: W.H. Freeman and Company, 1993. p. 

395. 

1-year and 3-year limits are summarized 

later and described in more detail in the 

Power Sector Variability TSD. 

Expected variability over a single 

year. EPA performed analyses using 

historical data to demonstrate that there 

is year-to-year variability in baseline 

emissions (even when emissions rates 

for all units are held constant) and to 

quantify the magnitude of this 

variability. This year-to-year variability 

in emissions is reflected, in combination 

with other factors, in year-to-year 

variability in air quality. 

The focus of the analysis is on 

quantifying the magnitude of the 

inherent variability in the baseline 

emissions (on both a 1-year and a 3-year 

basis). The goals of this analysis, 

therefore, are to determine the typical 

variability in emissions that is due to 

changes in generation, and not due to 

changes in emission limits, and to set 

emissions criteria limits that can be 

used as part of a remedy to ensure that 

states are eliminating their significant 

contribution and interference with 

maintenance to protect air quality. 

EPA used statewide average emissions 

rates projected using IPM to convert 

historical heat input variability into 

corresponding emissions variability 

limits. The approach assessed the 

variability in state-level heat input over 

a 7-year time period (2002 through 

2008) using the standard deviation and 

then determined the difference in 

emissions from the 95th percent twotailed confidence level and the mean.75

The approach resulted in a maximum 

allowable variability, in tons, for each 

state. These values were then divided by 

the mean emissions values over the 7- 

year time period to yield a percentage 

variability value for each state. See the 

Power Sector Variability TSD for details. 

From the state-by-state tonnage and 

percentage emission variability values, 

EPA identified a single set of variability 

levels (that is, a tonnage and a 

percentage) based on the historic 

variability. EPA made the decision to 

adopt a single, uniform tonnage and 

percentage level pairing to apply to all 

states in order to make the application 

of the variability limits straightforward 

rather than developing state-by-state 

percentage variability values. The effect 

of the pairing is to ensure that each state 

is allowed adequate variability while 

minimizing the total amount of 

emissions allowed. Using, for all states, 

only a constant percentage (reflecting 

emissions variability in smaller states 

with a greater range of emissions in 

percentage terms) would result in large 

states being allowed greater variability 

than needed. Conversely, using only a 

constant tonnage (reflecting emissions 

variability in larger states with a greater 

range of emissions in tonnage terms) 

would result in small states being 

allowed greater variability than needed. 

To ensure adequate variability limits— 

even in states with small numbers of 

units where expected variability would 

be more pronounced in percentage 

terms, and in large states where 

expected variability would be more 

pronounced in absolute tonnage terms— 

EPA derived variability limits both as a 

percentage and in terms of absolute 

emissions (tons) that serve to minimize 

the total amount of emissions allowed 

under this combination variability limit 

approach. 

For the tonnage and percentage limit 

criteria, EPA looked at a wide range of 

percentage and tonnage combinations, 

and chose for further investigation 

combinations that provided states 

sufficient variability limits (based on 

historic variability) and fit the 

requirement of minimizing the allowed 

emissions. Power plants in states that 

were close to the variability limits were 

evaluated more closely to ensure the 

modeling reflected all controls known to 

operate. EPA believes that the chosen 

limits would not be tighter than these 

states could be expected to meet. 

This approach (identifying both a 

tonnage and a percentage) addresses the 

difficulty that smaller states with fewer 

units could face if only percentages 

were used to set the limits. For instance, 

in a small state with a budget of 5,000 

tons of 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 change in statewide 

emissions. 

For both annual NOX and SO2, the 

percentage variability limits are 10 

percent of a state’s budget and the 

corresponding tonnage variability limits 

are 5,000 and 1,700 tons for 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 emissions over 

similar time periods, and to establish 

state budgets with variability limits that 

ensure that the significant contribution 

and interference with maintenance that 

EPA has identified in this notice be 

eliminated. 

While the year-to-year variability in 

emissions could lead to variability in 

3-year rolling averages, inherent 

variability is lower over a 3-year time 

period than over a 1-year period and 

thus a state’s 3-year variability limit will 

be lower than the state’s 1-year 

variability limit. Establishing such 

3-year limits thus provides an 

opportunity to ensure that the 

variability limits do not allow greater 

fluctuation in emissions than justified 

based on historic variability. EPA 

estimated the variability in a state’s 

emissions over a 3-year time period 

based on the expected variability in 

emissions for a single year. 

As summarized later and described in 

the Power Sector Variability TSD, the 

Agency used statistical methods to 

estimate the 3-year variability based on 

1-year variability. The average 

variability of a multi-year sample is the 

average variability of a single year 

divided by the square root of the 

number of years in the multi-year 

sample.76 Thus, the variability of a 

3-year average is equal to the annual 

variability divided by the square root of 

three. EPA used this approach to 

determine 3-year variability limits based 

on the 1-year limits. For example, the 

Agency calculated the 3-year variability 

that corresponds to a 1-year variability 

of 5,000 tons as 5,000 divided by the 


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square root of three, or 2,887 tons. 

Similarly, EPA calculated the 3-year 

variability that corresponds to a 1-year 

variability of 1,700 tons as 1,700 

divided by the square root of three, or 

981 tons. EPA decided to use three years 

instead of some other interval in order 

to be consistent with 3-year averaging 

used to assess attainment with the 

NAAQS, as explained earlier in this 

section. 

Proposed 3-year variability limits for 

each covered state are shown in the 

tables in section IV.F.2, later. See the 

Power Sector Variability TSD for more 

details on EPA’s variability approach. 

2. State Budgets With Variability Limits 

As explained previously, EPA 

determined variability limits for each 

state. EPA then applied these variability 

limits on a state-by-state basis to 

calculate state-specific emissions 

budgets with variability limits. EPA 

calculated state budgets with both 

1-year and 3-year variability limits. 

Table IV.F–1 shows proposed 

variability limits by state on 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 

21 and 28 percent of a state’s budget, 

respectively. Under this alternative 

calculation method, a state’s variability 

limit would be no lower than 10 percent 

of its budget and no higher than 21 or 

28 percent, for 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. 

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 28 percent of the 

budget (857 tons). Therefore, under this 

alternative calculation method, 

Connecticut’s 1-year SO2 variability 

limit would be 857 tons (28 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 21 percent of the 

budget (583 tons). Therefore, under this 

alternative approach, Connecticut’s 

1-year annual NOX variability limit 

would be 583 tons. Tables IV.F–1 

through IV.F–3 show the variability 

limits under the proposed and 

alternative calculation methods. See the 

Power Sector Variability TSD in the 

docket for this rule for more details. 

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 1,700 981 857 495 

Delaware .................................................................................................. 7,784 1,700 981 1,700 981 

District of Columbia .................................................................................. 337 1,700 981 94 54 

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 

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 5,728 3,307 5,728 3,307 

Kentucky .................................................................................................. 113,844 11,384 6,573 11,384 6,573 

Louisiana .................................................................................................. 90,477 9,048 5,224 9,048 5,224 

Maryland .................................................................................................. 39,665 3,967 2,290 3,967 2,290 

Massachusetts ......................................................................................... 7,902 1,700 981 1,700 981

Michigan ................................................................................................... 155,675 15,568 8,988 15,568 8,988 

Minnesota ................................................................................................ 47,101 4,710 2,719 4,710 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 4,079 2,355 4,079 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 28 percent of the state’s budget. If 1,700 tons is 

greater than 28 percent of the state’s budget, the state’s limit is set at 28 percent of its budget. If 1,700 tons is less than 10 percent of the state’s 

budget, the state’s limit is set at 10 percent of its budget. 


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TABLE IV.F–2—VARIABILITY LIMITS ON NOX ANNUAL EMISSIONS FOR 2014 AND LATER FOR ELECTRIC GENERATING UNITS

[Tons] 

State NOX annual 

Proposed Alternative 

1-year limit 

3-year 

average 

limit 

1-year limit 

3-year 

average 

limit 

Alabama ................................................................................................... 69,169 6,917 3,993 6,917 3,993 

Connecticut .............................................................................................. 2,775 5,000 2,887 583 336 

Delaware .................................................................................................. 6,206 5,000 2,887 1,303 752 

District of Columbia .................................................................................. 170 5,000 2,887 36 21 

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 

Kansas ..................................................................................................... 51,321 5,132 2,963 5,132 2,963 

Kentucky .................................................................................................. 74,117 7,412 4,279 7,412 4,279 

Louisiana .................................................................................................. 43,946 5,000 2,887 5,000 2,887 

Maryland .................................................................................................. 17,044 5,000 2,887 3,579 2,066 

Massachusetts ......................................................................................... 5,960 5,000 2,887 1,252 723 

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 2,483 1,434 

New York ................................................................................................. 23,341 5,000 2,887 4,902 2,830 

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 21 percent of the state’s budget. If 5,000 tons is 

greater than 21 percent of the state’s budget, the state’s limit is set at 21 percent of its budget. If 5,000 tons is less than 10 percent of the state’s 

budget, the state’s limit is set at 10 percent of its budget. 

The 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. 

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. 

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 27 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. 


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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 1,212 355 205 

Delaware .................................................................................................. 2,450 2,100 1,212 662 382 

District of Columbia .................................................................................. 105 2,100 1,212 28 16 

Florida ...................................................................................................... 56,939 5,694 3,287 5,694 3,287 

Georgia .................................................................................................... 32,144 3,214 1,856 3,214 1,856 

Illinois ....................................................................................................... 23,570 2,357 1,361 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 1,953 1,127 

Michigan ................................................................................................... 28,253 2,825 1,631 2,825 1,631 

Mississippi ................................................................................................ 16,530 2,100 1,212 2,100 1,212 

New Jersey .............................................................................................. 5,269 2,100 1,212 1,423 821 

New York ................................................................................................. 11,090 2,100 1,212 2,100 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 

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 27 percent of the state’s budget. If 2,100 tons is 

greater than 27 percent of the state’s budget, the state’s limit is set at 27 percent of its budget. If 2,100 tons is less than 10 percent of the state’s 

budget, the state’s limit is set at 10 percent of its budget. 

As discussed in section V.D, the 

proposed FIPs would apply the 1-year 

variability limits commencing in 2014 

and the 3-year variability limits 

commencing in 2016, noting that 

application of the 3-year average limits 

in 2016 would serve to limit each state’s 

emissions in 2014 and 2015. The 

Agency also requests comment on 

whether the remedy in the proposed 

FIPs should be modified so that the 

limits would apply starting in 2012 

instead of 2014. In addition, the direct 

control remedy option on which EPA 

requests comments includes assurance 

provisions based on these variability 

limits that would apply starting in 2012. 

Thus, EPA also explains later what 

variability limits would apply in 2012 

and 2013. The 1-year variability limits 

for 2012 and 2013 would be the same 

as the variability limits for 2014 and 

later in Tables IV.F–1, IV.F–2, and IV.F– 

3 for all state budgets except for the 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 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.F–3. 

For an alternative approach where 

variability limits start in 2012 instead of 

2014, EPA considered—instead of twoyear 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 


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

years spanning the two budget levels is 

less straightforward. EPA analyzed this 

alternative method for the 15 SO2 group 

1 states and compared results to the 

results using the 2-year average limits in 

2012 and 2013 for these states, and 

determined that the 2-year average 

approach is reasonable. See the Power 

Sector Variability TSD for more 

information. 

Table IV.F–4 includes 1-year and 

2-year variability limits calculated 

according to the proposed methodology. 

The 2-year limits are the 1-year limits 

divided by the square root of two. The 

table does not include separate columns 

with variability limits calculated 

according to the alternative calculation 

method (i.e., the method that adds a 

ceiling based on the maximum 

percentage of variability in historic data, 

described previously) because for the 

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 6,650 

Kentucky .................................................................................................................................................. 219,549 21,955 15,524 

Michigan ................................................................................................................................................... 251,337 25,134 17,772 

Missouri .................................................................................................................................................... 203,689 20,369 14,403 

New York ................................................................................................................................................. 66,542 6,654 4,705 

North Carolina .......................................................................................................................................... 111,485 11,149 7,883 

Ohio ......................................................................................................................................................... 464,964 46,496 32,878 

Pennsylvania ............................................................................................................................................ 388,612 38,861 27,479 

Tennessee ............................................................................................................................................... 100,007 10,001 7,072 

Virginia ..................................................................................................................................................... 72,595 7,260 5,133 

West Virginia ............................................................................................................................................ 205,422 20,542 14,526 

Wisconsin ................................................................................................................................................. 96,439 9,644 6,819 

1-year variability limits calculated by the proposed method are the larger of (1) 1,700 tons or (2) 10 percent of the state’s budget. Two-year 

limits are the 1-year limits divided by the square root of two. 

The alternative 1-year variability limit is 1,700 tons as long as that amount is between 10 and 28 percent of the state’s budget. If 1,700 tons is 

greater than 28 percent of the state’s budget, the state’s limit is set at 28 percent of its budget. If 1,700 tons is less than 10 percent of the state’s 

budget, the state’s limit is set at 10 percent of its budget. The alternative calculation method would yield identical limits to the limits determined 

using the proposed method for the budgets in Table IV.F–4, because for each of these budgets, 1,700 tons is less than 10 percent of the 

budget. 

3. Summary of Emissions Reductions 

Across All Covered States 

Table IV.F–5 presents projected 

power sector emissions in the base case 

(i.e., without the proposed Transport 

Rule or CAIR) compared to projected 

emissions with the proposed Transport 

Rule in 2012 and 2014 for all covered 

states. Table IV.F–6 presents 2005 

historical power sector emissions 

compared to projected emissions with 

the Transport Rule in 2012 and 2014. 

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 

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 


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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—Continued 

[Million tons] 

2005 actual 

emissions 

2012 

transport 

rule emissions 

2012 

emissions 

reductions 

from 2005 

2014 

transport 

rule emissions 

2014 

emissions 

reductions 

from 2005 

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 DC 

Circuit. As discussed in section III 

previously, the DC Circuit has issued 

two significant decisions addressing the 

requirements of 110(a)(2)(D)(i)(I). The 

first opinion largely upheld the NOX SIP 

Call, Michigan v. EPA, 213 F.3d 663 (DC 

Cir. 2000), and the second found 

significant flaws in the CAIR, North 

Carolina v. EPA, 531 F.3d. 896 (DC Cir. 

2008). In both cases, the Court 

considered aspects of the methodology 

used by EPA to identify emissions that, 

pursuant to section 110(a)(2)(D)(i)(I), 

must be eliminated due to their impact 

on air quality in downwind states. EPA 

believes that the methodology used in 

this proposed Transport Rule is 

consistent with both opinions and 

rectifies the flaws the North Carolina 

Court identified with the methodology 

used in CAIR. The methodology used 

for this proposed rule relies on statespecific data to analyze each individual 

state’s significant contribution, uses air 

quality considerations in addition to 

cost considerations to identify each 

state’s significant contribution, and 

gives independent meaning to the 

‘‘interference with maintenance’’ prong. 

This methodology is then applied in a 

reasonable manner consistent with the 

relevant judicial opinions. 

In North Carolina, the Court held that 

EPA’s approach to evaluating significant 

contribution was inadequate because, by 

evaluating only whether emissions 

reductions were highly cost effective ‘‘at 

the regional level assuming a trading 

program’’, it failed to conduct the 

required state-specific analysis of 

significant contribution. See id. at 907. 

EPA, the Court concluded, ‘‘never 

measured the ‘significant contribution’ 

from sources within an individual state 

to downwind nonattainment areas.’’ Id. 

The Court did not, however, disturb the 

air-quality-based methodology used by 

EPA to identify the states with 

contributions large enough to warrant 

further consideration. 

For this proposed transport rule, EPA 

uses a first step similar to that used in 

the CAIR to identify the states with 

relatively large contributions. However, 

in contrast to the CAIR, it then uses a 

state-specific analysis. Instead of 

identifying a single emissions level that 

could be achieved by the application of 

highly cost effective controls in the 

region, EPA determines, on a state-bystate basis what reductions could 

effectively be achieved by sources in 

that state. EPA’s new approach does not, 

as the CAIR methodology did, establish 

a regional cap on emissions that is then 

divided into state budgets that set the 

emission reduction requirements for 

each state. Instead, EPA develops, for 

each covered state, emissions budgets 

based on the reductions achievable at a 

particular cost per ton in that particular 

state, taking into account the need to 

ensure reliability of the electric 

generating system. The selected cost/ton 

levels reflect consideration of both cost 

factors and air quality factors including 

the estimated impact of upwind states’ 

emissions on each downwind receptor. 

In addition, in developing this 

approach, EPA was guided by the 

Court’s holdings regarding the use of 

cost to identify significant contribution. 

Specifically, the Court held in Michigan 

that EPA could ‘‘in selecting the 

‘significant’ level of ‘contribution’ under 

section 110(a)(2)(D)(i)(I), choose a level 

corresponding to a certain reduction in 

cost.’’ North Carolina, 531 F.3d at 917 

(citing Michigan, 213 F.3d at 676–77). 

This holding also supported the Court’s 

conclusion in Michigan that it was 

acceptable for EPA to apply a uniform 

cost-criterion across states. See 

Michigan, 213 F.3d at 679. In the CAIR 

case, the Court rejected EPA’s analysis, 

not because it relied on cost 

considerations to identify significant 

contribution, but because it found that 

EPA had failed to draw the significant 

contribution line at all. See North 

Carolina, 531 F.3d at 918 (‘‘* * * here 

EPA did not draw the [significant 

contribution] line at all. It simply 

verified sources could meet the 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 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 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 


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77Certain 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. 

78Emissions estimates are based on the 2012 

baseline projections described in section IV in this 

preamble. 

‘‘gave no independent significance to the 

‘interfere with maintenance’ prong of 

section 110(a)(2)(D)(i)(I) to separately 

identify upwind sources interfering 

with downwind maintenance.’’ North 

Carolina, 531 F.3d at 910. EPA rectified 

this flaw in this rulemaking by 

separately identifying downwind 

‘‘nonattainment sites’’ and downwind 

‘‘maintenance sites.’’ EPA decided to 

consider upwind states’ contributions 

not only to sites that EPA projected 

would be in nonattainment, but also to 

sites that, based on the historic 

variability of their emissions, EPA 

determined may have difficulty 

maintaining the relevant standards. The 

specific mechanism EPA used to 

implement this approach is described in 

detail in section IV.C. previously. For 

annual 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 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. 

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 μg/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 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 

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 manmade 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

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 Web site at: 

(http://www.epagov/airmarkets/ 

progsregs/cair/multi.html). EPA’s IPM 

analysis for CAIR is another example: 

(http://www.epagov/airmarkets/ 

progsregs/epa-ipm/cair/index.html). 

Based on these analyses, EPA believes 

that there exist reasonable means for 

EGUs to make substantial reductions in 

emissions of SO2 and NOX. EPA also 

believes that, at this time, EGUs can 


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

that were included in the CAIR NOX ozone season 

trading program. 

80Section 172(a)(2) of the Clean Air Act provides 

that ‘‘the attainment date for an area designated 

nonattainment with respect to a national primary 

ambient air quality standard shall be the date by 

which attainment can be achieved as expeditiously 

as practicable, but no later than 5 years from the 

date such area was designated nonattainment under 

section 7407(d) of this title, except that the 

Administrator may extend the attainment date to 

the extent the Administrator determines 

appropriate, for a period no greater than 10 years 

from the date of designation as nonattainment, 

considering the severity of nonattainment and the 

availability and feasibility of pollution control 

measures.’’ Designations for the 2006 24-hour PM2.5

NAAQS became effective on December 14, 2009. 

reduce SO2 and NOX emissions more 

cost-effectively than other source 

categories (see section IV.D for 

discussion of control costs for non-EGU 

source categories). For these reasons, 

EPA has decided to require reductions 

in SO2 and NOX emissions from EGUs 

in the FIPs in this proposed rule. EPA 

requests comments on these proposed 

FIPs and its proposal to require 

reductions from EGUs. 

2. Other Source Categories Are Not 

Included 

In these proposed FIPs, EPA is not 

proposing to include emission reduction 

requirements for sources other than 

EGUs.79

a. Why EPA Does Not Require 

Reductions From Other Source 

Categories To Address Transport 

Requirements for 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 EGUs are available 

at a cost per ton that is lower than the 

cost per ton of non-EGU controls. Other 

analyses discussed in section IV.D 

demonstrated that these EGU reductions 

are sufficient to eliminate the quantity 

of emissions identified by EPA as 

significantly contributing to or 

interfering with maintenance of the 

1997 PM2.5 NAAQS in downwind areas. 

This same section explains that EGU 

reductions substantially address 

eliminating the quantity of emissions 

identified by EPA as significantly 

contributing to or interfering with 

maintenance of the 2006 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 nonEGU sources in order to eliminate 

significant contribution and interference 

with maintenance for any other 

NAAQS, including the 1997 ozone 

NAAQS and future NAAQS for 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 non-EGU 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 non-EGU NOX

controls. The same section also explains 

the need for EPA to further analyze 

whether fully addressing upwind state 

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. Sources will be required 

to comply with the annual SO2 and NOX

requirements by January 1, 2012 and 

January 1, 2014 for the first and second 

phases, respectively. Similarly, sources 

will be required to comply with the 

ozone season NOX requirements by May 

1, 2012, and by May 1, 2014. EPA chose 

these dates to coordinate with the 

NAAQS attainment deadlines and to 

assure that reductions are made as 

expeditiously as practicable, as 

described later in this section. This 

section also discusses how the 

compliance deadlines address the 

Court’s concern about timing. 

Additionally, this section explains that 

EPA will consider additional reductions 

to address the NAAQS in the future. 

1. Date for Prohibiting Emissions That 

Significantly Contribute or Interfere 

With Maintenance of the 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 2019.80

Upwind emissions reductions 

achieved by the 2014 emissions year 

will help areas that failed to meet the 

April 2010 deadline, to meet the April 

2015 deadline for the 1997 PM2.5

NAAQS. These reductions will also 

help areas meet the December 2014 

attainment deadline with respect to 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). 


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81This proposed cumulative, seasonal standard is 

expressed as an annual index of the sum of 

weighted hourly concentrations, cumulated over 12 

hours per day (8 a.m. to 8 p.m.) during the 

consecutive 3-month period within the O3 season 

with the maximum index value, set at a level within 

the range of 7 to 15 ppm-hours. 

2. Date for Prohibiting Emissions That 

Significantly Contribute or Interfere 

With Maintenance of the 1997 Ozone 

NAAQS 

Ozone nonattainment areas must 

attain permissible levels of ozone ‘‘as 

expeditiously as practicable,’’ but no 

later than the date assigned by EPA in 

the ozone implementation rule (40 CFR 

part 51). The areas designated 

nonattainment in 2004 with respect to 

the 1997 8-hour ozone NAAQS in the 

eastern United States were assigned 

maximum attainment dates 

corresponding to the end of the 2006, 

2009, and 2012 ozone seasons. Many 

areas have already attained due in part 

to CAIR, federal mobile source 

standards, and other local, state, and 

federal measures. Those that have not 

yet attained the standard have 

maximum attainment dates ranging 

from 2010 (these are the 2009 areas that 

have been granted a 1-year extension 

due to clean data in 2009) to 2018. 

Areas designated ‘‘serious’’ 

nonattainment areas have a June 2013 

maximum attainment deadline. The 

proposed Transport Rule’s first phase of 

reductions in 2012 will help the 

remaining areas with June 2013 

maximum attainment deadlines attain 

the 1997 8-hour ozone NAAQS by their 

deadline. The reductions will also 

improve air quality in areas with later 

deadlines. 

3. Reductions Required by 2012 To 

Ensure That Significant Contribution 

and Interference With Maintenance Are 

Eliminated as Expeditiously as 

Practicable 

EPA is requiring an initial phase of 

reductions by 2012. These reductions 

are necessary to ensure that significant 

contribution and interference with 

maintenance are eliminated as 

expeditiously as practicable. This will 

in turn assist downwind states to 

achieve attainment as expeditiously as 

practicable as required by the CAA. 

Because the proposed rule, if 

finalized, will replace the CAIR, EPA 

cannot assume that after this rule is 

finalized, EGUs would continue to emit 

at the reduced emissions levels 

achieved by CAIR. Instead, it is the 

emissions reductions requirements in 

the proposed FIPs that will determine 

the level of EGU emissions in the 

eastern United States. For these reasons, 

EPA is proposing to require an initial 

phase of reductions by 2012 which 

would ensure that existing and planned 

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 (DC Cir. 

2008), and described previously, EPA 

has established the compliance 

deadlines in the proposed rule based on 

the respective NAAQS attainment 

requirements and deadlines applicable 

to the downwind nonattainment and 

maintenance sites. 

The 2012 deadline for compliance 

with the limits on ozone-season 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 

is also consistent with the requirement 

that states attain the NAAQS as 

expeditiously as practicable. 

The 2014 deadline for compliance 

with the limits on annual 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 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 emissions 

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. 

5. EPA Will Consider Additional 

Reductions in Pollution Transport To 

Assist in Meeting Any Revised or New 

NAAQS 

a. Ozone 

As noted, in a January 19, 2010, 

notice of proposed rulemaking, EPA 

proposed to strengthen the NAAQS for 

ozone. In that notice, EPA proposed 

levels for the ozone standard to a level 

within the range of 0.060 to 0.070 parts 

per million. EPA also proposed in this 

same notice to establish a distinct 

cumulative, seasonal ‘‘secondary’’ 

standard, designed to protect sensitive 

vegetation and ecosystems, including 

forests, parks, wildlife refuges and 

wilderness areas.81

EPA expects to finalize the revised 

NAAQS for ozone in August 2010. After 

the NAAQS are finalized, EPA will be 

able to identify areas that are expected 

to have difficulty attaining and 

maintaining those standards and will 

evaluate and analyze the impact of 

upwind state emissions in those areas 

with regard to those standards. EPA has 

already begun the technical background 

work necessary to allow it to move 

quickly, once the revised ozone 

standards are promulgated, with a 

proposal to address upwind emissions 

that significantly contribute to 

nonattainment of or interfere with 

maintenance of those standards. 

Because that analysis will take some 

time, and because EPA recognizes the 

urgency of responding to the concerns 

raised by the Court in North Carolina v. 

EPA, EPA intends to address the 

requirements of 110(a)(2)(D)(i)(I) with 

respect to the revised ozone standards 

in a subsequent proposal. Addressing 

the 110(a)(2)(D)(i)(I) requirements for 

the new NAAQS shortly after 

promulgation of those NAAQS would 

help clarify the requirements related to 

transported emissions before downwind 

state nonattainment SIPs are due. In 

doing so, the transport rule would aid 

downwind states in developing plans 

for attaining and maintaining the new 

NAAQS. 

b. Fine Particles 

EPA is also on a schedule to review 

and, if necessary update the PM2.5

NAAQS. This review is scheduled for 

completion in October 2011. EPA plans 


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to conduct background technical 

analyses so that EPA will be prepared to 

move quickly, if necessary, with a 

transport rule related to any revised 

PM2.5 NAAQS. 

D. Implementing Emissions Reductions 

Requirements 

In this rule, EPA is proposing FIPs to 

eliminate the significant contribution 

and interference with maintenance EPA 

has identified in this action. We are 

proposing one ‘‘remedy’’ option to 

implement the necessary emissions 

reductions and taking comment on two 

other options. Before presenting these 

options we briefly summarize the 

approaches used in the 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 ozone-season 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 cost-effective 

NOX reductions. Created after years of 

scientific research and air quality data 

analyses showed that upwind 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. 

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 reduced 

emissions beyond required levels, it 

could sell the unused allowances or 

bank (save) them for use in a future 

ozone season. To accurately monitor 

and report emissions, sources use 

continuous emission monitoring 

systems (CEMS) or other approved 

monitoring methods under EPA’s 

stringent monitoring requirements (Title 

40 of the Code of Federal Regulations 

[CFR], Part 75). 

The NOX SIP Call cap and trade 

program was a way to make costeffective 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, 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 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 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 


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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 DC 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 of amount of 

contribution, reduce their NOX by an 

amount achievable with ‘‘highly costeffective controls.’’ Id. at 679. EPA’s 

approach, Petitioners first alleged, was 

irrational because it did not take into 

account differences in individual states’’ 

respective contributions to downwind 

nonattainment. Both small and large 

contributors were required to make 

reductions achievable by the application 

of highly cost effective controls. The 

court rejected this challenge finding that 

this result ‘‘flows ineluctably from EPA’s 

decision to draw the ‘significant 

contribution’ line on the basis of cost 

differentials.’’ Id. 

Petitioners’ second objection to the 

use of uniform controls was that it failed 

to take into account the fact that the 

location of emissions reductions may 

affect the impact of those reductions on 

downwind nonattainment areas. 

Petitioners argued that because 

reductions closer to the nonattainment 

area have a greater benefit, EPA’s use of 

a highly-cost-effective standard and 

region-wide emissions trading did not 

guarantee that it would have secured the 

rule’s health benefits at the lowest cost. 

See id. The Court rejected this challenge 

also, giving deference to EPA’s 

judgment that non-uniform regional 

approaches would not ‘‘ ‘provide either 

a significant improvement in air quality 

or a substantial reduction in cost.’ ’’ Id. 

(quoting 63 FR 57423). 

Petitioners challenging the CAIR also 

raised issues related to EPA’s use of an 

interstate trading program to satisfy the 

requirements of section 

110(a)(2)(D)(i)(I). Petitioners challenged 

both the trading program itself and the 

state budgets. These budgets were used 

to determine the number of emission 

allowances allocated to sources in each 

state or, if the state chose not to 

participate in the trading programs, the 

specific emission reduction 

requirements for that state. 

The Court concluded, in North 

Carolina v. EPA, 531 F.3d 896, that EPA 

had not demonstrated that the 

110(a)(2)(D)(i)(I) remedy promulgated in 

CAIR would effectuate the statutory 

mandate of section 110(a)(2)(D)(i)(I) and 

promote the goal of prohibiting 

contributing sources within one state 

from contributing to nonattainment in 

another state. In reaching this 

conclusion, the Court emphasized that 

EPA had not adequately measured each 

individual state’s significant 

contribution. See id. at 908. (‘‘It is 

unclear how EPA can assure that the 

trading programs it has designed in 

CAIR will achieve section 

110(a)(2)(D)(i)(I)’s goals if we do not 

know what each upwind state’s 

‘‘significant contribution’’ is to another 

state.’’) 

The Court also emphasized that 

section 110(a)(2)(D)(i)(I) ‘‘prohibits 

sources ‘within the State’ from 

‘contribut[ing] significantly to 

nonattainment in * * * any other State 

* * *’ ’’ Id. at 907. (quoting section 

110(a)(2)(D)(i)(I) and adding emphasis). 

While recognizing that it was ‘‘possible 

that CAIR would achieve section 

110(a)(2)(D)(i)(I)’s goals’’ it concluded 

that ‘‘CAIR assures only that the entire 

region’s significant contribution will be 

eliminated,’’ and that ‘‘EPA is not 

exercising its section 110(a)(2)(D)(i)(I) 

duty unless it is promulgating a rule 

that achieves something measurable 

toward the goal of prohibiting sources 

‘‘within the State’’ from contributing to 

nonattainment or interfering with 

maintenance ‘‘in any other State.’’ Id. at 

907. Furthermore, since CAIR was 

designed as a ‘‘complete remedy to 

section 110(a)(2)(D)(i)(I) problems’’ the 

Court emphasized that ‘‘it must actually 

require elimination of emissions from 

sources that contribute significantly and 

interfere with maintenance.’’ Id. at 908. 

In doing so, however, the Court also 

acknowledged that it had accepted in 

Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 

2000) EPA’s decision to apply uniform 

emissions controls and its consideration 

of cost in the definition of significant 

contribution. See North Carolina, 531 

F.3d at 908. 

In developing options to eliminate the 

emissions identified as constituting all 

or part of a state’s significant 

contribution and interference with 

maintenance, EPA has been mindful of 

the direction provided by the Court. As 

discussed in greater detail later, EPA 

believes that each of the remedy options 

presented is consistent with the Court’s 

opinions interpreting the requirements 

of section 110(a)(2)(D)(i)(I). 

3. Remedy Options Overview 

EPA is proposing one ‘‘remedy’’ 

option to implement the emissions 

reductions requirements and taking 

comment on two alternatives. This 

section provides a brief overview of the 

proposed remedy and the two 

alternatives. Sections V.D.4, V.D.5, and 

V.D.6, later, describe the proposed 

remedy and the alternatives in detail. 

EPA considered a full range of remedy 

options in developing this proposal. 

Among other things, EPA considered 

variations of direct control options, 

intrastate cap and trade, interstate cap 

and trade, hybrids of these approaches, 

and simple state emissions caps. 

Stakeholders have suggested a variety of 

remedy options for EPA’s consideration. 

A TSD in the docket entitled ‘‘Other 

Remedy Options Evaluated’’ describes 

other options that EPA evaluated. 

Based on its consideration of a range 

of options, EPA is proposing one 

remedy option and requesting comment 

on two alternatives. The proposed 

remedy option, discussed later, is a 

hybrid approach that combines limited 

interstate trading with other 

requirements. The alternative remedies 

on which EPA requests comment 

include an intrastate trading option and 

a direct control option. The proposed 

and alternative remedy options would 

regulate 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 state-specific control budgets 

and allow for intrastate and limited 

interstate trading of emissions 

allowances allocated to EGUs. This 

approach would assure environmental 

results while providing some limited 

flexibility to covered sources consistent 

with the Court decision as described 

later. The approach would also help 

ease the transition for implementing 

agencies and covered sources from CAIR 

to the Transport Rule. Based on 

consideration of a range of options, EPA 

believes that the proposed option is the 

best approach, for the reasons discussed 

in section V.D.4. 

The Agency is also presenting other 

alternative remedies for comment. The 

first alternative for which EPA requests 

comment would use state-specific 

control budgets and allow intrastate 

trading of emissions allowances 

allocated to EGUs, but no interstate 


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82Note that the report evaluating this alternative 

was a theoretical economic and air quality analysis 

of the concept. It did not explore how trading ratios 

would be incorporated into a workable trading 

program. It did however indicates that the 

‘‘approach also provides for the possibility that the 

emission weights developed by this analysis could 

be incorporated into an emission trading program 

in which emission weights act like exchange rates 

between different subregions and species. However 

this adds a significant increase in the complexity 

of the market and in practical terms is worth 

considering only when the potential cost savings 

are large enough to offset the additional complexity 

in market structure.’’ P. 1–7, Stratus Consulting Inc. 

November 24, 1999. 

trading. The second alternative for 

which EPA requests comment is a direct 

control program in combination with 

state-specific control budgets. 

EPA recognizes there could be cost 

savings from an approach that uses aless 

restrictiveinterstate trading option. EPA 

also recognizes that unrestricted trading 

programs including the NOX SIP Call 

Trading Program have been very 

successful in addressing regional 

pollution problems. 

In this action, EPA is not proposing 

such an unrestricted trading program, 

because EPA does not believe that such 

an option could provide assurance that 

each state achieves emissions 

reductions within the state, as required 

by the North Carolina decision. As the 

D.C. Circuit emphasized in its opinion, 

the statutory requirement in section 

110(a)(2)(D)(i)(I) aims to prohibit 

‘‘sources ‘‘within the State’’ from 

contributing to nonattainment or 

interfering with maintenance in ‘‘any 

other State.’’ North Carolina, 531 F.3d at 

908. The location of emission 

reductions is relevant because it can 

influence where air quality 

improvements occur and whether a 

particular state meets its statutory 

obligations. See North Carolina, 531 

F.3d at 907. 

In addition to considering 

unrestricted trading, EPA also 

considered whether there were other 

ways that a trading program could be 

structured to address the Court’s 

concerns. In particular, EPA reviewed a 

methodology that had been investigated 

during the development of the NOX SIP 

Call regulation that used trading ratios 

(‘‘Development and Evaluation of a 

Targeted Emission Reduction Scenario 

for NOX Point Sources in the Eastern 

United States: An Application of the 

Regional Economic Model for Air 

Quality (REMAQ)’’, Prepared by Stratus 

Consulting inc. November 24, 1999) (at 

http://www.epagov/airtransport). This 

approach would allow interstate 

trading, but use trading ratios to take 

into account differences in the 

cumulative downwind impact of 

emissions from different states. Trading 

ratios would be developed for each pair 

of states using air quality modeling such 

that, given the meteorological 

assumptions underlying the air quality 

modeling, the ratios would represent the 

ratio of the benefit to downwind air 

quality within a region from controlling 

emissions in different upwind areas. For 

instance, in its simplest form, if 

emission reductions from State A were 

twice as effective at reducing 

cumulative downwind air quality 

impact on a set of downwind receptors 

as emission reductions from State B, the 

trading ratio between States A and B 

would be 2 to 1.82 In other words, if the 

States chose to trade, State A would 

have to purchase 2 allocations from 

State B to cover 1 ton of State A’s 

emissions, since State A’s emissions 

have twice the impact on downwind air 

quality. Such an approach offers the 

very valuable potential to address the 

transport problem in an effective (and 

potentially less costly) manner, as it 

incentivizes reductions from the places 

where they have the greatest value in 

reducing downwind air quality 

problems. While it offers such 

opportunities, there are challenges in 

developing such a system that is 

consistent with the requirement under 

section 110(a)(2)(D) that emission 

reductions occur in particular 

geographic locations. The trading ratio 

approach would be designed to assure a 

cumulative downwind air quality result, 

not to assure specific upwind 

reductions. Although it would reduce 

the incentive for sources from upwind 

states with larger cumulative impacts to 

comply by purchasing allowances (since 

they would need to purchase a greater 

number of allowances per ton emitted 

than sources in states with less of an 

impact), as currently contemplated it 

would not be possible under this 

approach to include enforceable legal 

requirements to ensure that a specific 

state’s emissions remain below a 

specified level or to ensure that a 

specific amount of reductions occur 

within a particular state. EPA 

specifically requests comment on 

whether a ratios trading program could 

be designed to provide such a legal 

assurance. We also seek comment on 

whether such an assurance would be 

needed if, for example, in practice 

modeling results predicted with 

confidence that sufficient state-by-state 

reductions would be achieved under 

such an approach. 

In the SIP Call, EPA did not 

ultimately propose this methodology for 

several reasons. First, the Stratus 

Consulting study (‘‘Development and 

Evaluation of a Targeted Emission 

Reduction Scenario for NOX Point 

Sources in the Eastern United States: An 

Application of the Regional Economic 

Model for Air Quality (REMAQ)’’) 

estimated that the most significant cost 

savings occurred from moving from a 

uniform direct control approach to a 

conventional cap-and-trade approach 

(the study suggested that this would 

lead to cost savings of approximately 25 

percent). Adding trading ratios added 

significant complexity while only very 

slightly lowering costs (1 percent to 5 

percent compared to conventional cap 

and trade, where the cost savings 

decreased as the problem being 

addressed became more widespread 

(e.g. cost savings for the more stringent 

1997 8 hour ozone NAAQS standard 

would be less than cost savings for the 

less stringent early 1 hour standard)) 

(Stratus, page s–2). However, because 

the transport rule is a larger program 

covering multiple pollutants with a 

different set of non-attainment areas and 

a broader geographic scope, there is the 

potential for greater cost savings. 

Second, the trading ratios are dependent 

upon the meteorological assumptions 

used to develop them; to the extent that 

future year meteorology or costs turn 

out to be different, the trading ratios 

could in fact lead to less than predicted 

downwind air quality benefits. Notably 

in reality, the ratios would have to 

consider that the upwind states that 

impact a downwind receptor vary from 

receptor to receptor; conversely each 

upwind state contributes to different 

sets of downwind receptors. It would be 

very challenging to develop trading 

ratios that account for this myriad of 

different relationships. EPA believes 

these concerns are also valid in the 

context of this Transport Rule. 

In addition, in considering this 

approach in the original SIP Call, it took 

close to a year to perform the underlying 

analysis to develop ratios for 1 pollutant 

(NOX) and one downwind air quality 

problem (ozone). In this context, there 

are 3 pollutants (annual NOX, annual 

SO2 and ozone season NOX) and two 

downwind air quality problems (ozone 

and PM2.5) to consider. 

EPA requests comment on the trading 

ratios approach, including whether: The 

trading ratio approach described above 

would be consistent with the Court 

opinion in North Carolina v. EPA and 

satisfy the section 110(a)(2)(D) 

requirement that reductions occur 

‘‘within the state’’; there are ways the 

approach could be modified to be 

consistent with the Court opinion and 

the statutory requirement; there are 

ways that such an approach could 

administratively be put in place by 2012 

and be modified and adopted if further 

reductions are required to address 


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83EPA, however, has proposed variability limits 

to these budgets, and it is possible a ratios approach 

may imply emissions would fall within the 

variability limits if the ratios ultimately turned out 

to be close to one-to-one. 

84The 32 states are: Alabama, Arkansas, 

Connecticut, District of Columbia, Delaware, 

Florida, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Louisiana, Maryland, Massachusetts, 

Michigan, Minnesota, Mississippi, Missouri, 

Nebraska, New Jersey, New York, North Carolina, 

Ohio, Oklahoma, Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West Virginia, and 

Wisconsin. As noted in section III, for purposes of 

this rulemaking, when we discuss ‘‘states’’ we are 

also including the District of Columbia. 

future NAAQS; and on whether there 

are ways that such a system could be 

designed to be transparent and 

relatively simple for sources to 

understand and comply with. 

Analysis from the SIP Call suggests 

that the trading ratios approach might 

have the potential to slightly reduce 

costs. However, the approach, as 

envisioned, appears to be in tension 

with EPA’s mandate under section 

110(a)(2)(D)(i)(I) to assure that 

significant contribution is fully 

addressed in each upwind state. While 

such an approach would ensure 

reductions on a region-wide basis, EPA 

has not been able to identify a way that 

the trading ratio approach could be 

modified to assure a specific set of 

downwind emissions reductions from 

all states. Under such an approach, 

there is the potential that some upwind 

states might make reductions that are 

larger than their significant 

contribution, while other states might 

make reductions that are less than their 

significant contribution. Because the 

state budgets have been designed to 

achieve all reductions available at a 

given cost, trading ratios other than one 

to one, although providing equivalent 

improvements in downwind air quality 

would lead to emissions reductions that 

were inconsistent with the initial 

budgets.83

Because EPA recognizes the potential 

cost savings and potential 

improvements in program effectiveness 

associated with less restricted trading 

options, EPA is also requesting 

comment on the appropriateness of the 

assurance provisions that have been 

proposed, including whether they are 

adequate to assure that significant 

contribution and interference with 

maintenance are addressed in each 

state, whether they are overly 

restrictive, and whether there are less 

restrictive options that would provide 

adequate assurance that the statutory 

mandate is satisfied while providing 

more flexibility. Alternative approaches 

could potentially include: Using the 

basic methodology proposed with a 

higher or lower variability limitation or 

using an alternative to the approach to 

assure that state emissions budgets are 

met (e.g., trading ratios designed to 

assure that certain upwind emission 

reduction targets are met, rather than 

trading ratios designed to assure that 

downwind air quality goals are met). 

With regards to the variability limits 

that EPA has proposed, EPA takes 

comment on alternative approaches to 

calculating those limits, such as 

considering confidence intervals 

different than a 95 percent confidence 

interval such as a 99 percent confidence 

interval (For more information see TSD, 

‘‘Power Sector Variability’’.) 

EPA specifically requests that any 

commenter suggesting a less restrictive 

approach address how the commenter’s 

preferred approach would satisfy the 

statutory mandate in section 

110(a)(2)(D)(i)(I) of the Clean Air Act 

and be consistent with the decision of 

the DC Circuit in North Carolina v. EPA, 

531 F.3d 8906 (2008) (e.g., if 

commenters suggest a higher variability 

limitation, what would be the rationale 

for allowing that amount of variability; 

if commenters suggest an alternative 

framework, how would that framework 

assure that reductions occur ‘‘within the 

state’’) as well as how EPA could 

develop the approach in a way that 

would be workable for sources, states, 

and EPA in time to achieve emission 

reductions in 2012 (e.g., would an 

approach with trading ratios impact 

transaction costs or be overly complex 

for less sophisticated trading entities, 

can the analysis needed to develop the 

approach be completed in a timely 

way). 

As discussed in section IV.E, EPA is 

proposing new state budgets developed 

on a different basis from the CAIR 

budgets. The intrastate and interstate 

trading remedy options would use new 

allowance allocations, also developed 

on a different basis from the CAIR FIP 

allowance allocations. See section IV for 

the proposed state budget approach and 

section V.D.4 for proposed allowance 

allocation approaches. 

As discussed in section IV.F, EPA 

believes that inherent variability in 

power system operations affects each 

state’s baseline emissions and thus also 

affects a state’s emissions after 

elimination of all significant 

contribution and interference with 

maintenance. Thus, emissions may vary 

somewhat after implementation of the 

remedies under consideration. This 

includes the proposed remedy option 

(State Budgets/Limited Trading), the 

intrastate trading alternative, and the 

direct control alternative. Sections 

V.D.4, V.D.5, and V.D.6 describe 

variability approaches for the proposed 

remedy and each of the alternative 

remedies. 

EPA also considered only establishing 

state emissions caps. Such an approach 

would define what must be done to 

eliminate all (or in some cases part) of 

each state’s significant contribution and 

interference with maintenance, but it 

would not implement specific 

requirements to eliminate those 

emissions. As described in section III.C 

in this preamble, EPA decided to 

implement the emission reduction 

requirements through FIPs. To do so, 

EPA recognized that it needed to do 

more than establish simple state 

emissions caps. For this reason, EPA 

rejected the simple state emission cap 

option. 

As with any FIP that EPA issues, a 

covered state may submit, for review 

and approval, a state implementation 

plan (SIP) that replaces the Federal 

requirements with state requirements 

that would achieve the required 

reductions. A state’s SIP submission to 

replace the Transport Rule FIP might 

propose to use any remedy of the state’s 

choosing that actually eliminates the 

emissions that significantly contribute 

to nonattainment or interfere with 

maintenance downwind. Section VII in 

this preamble further discusses SIP 

submissions. 

4. State Budgets/Limited Trading 

Proposed Remedy 

In this action, EPA is proposing FIPs 

that would establish state-specific 

emission control requirements using 

state budgets starting in 2012 in 32 

states.84 This remedy option would 

allow unlimited intrastate trading and 

limited interstate trading to account for 

variability in the electricity sector, but 

also includes assurance provisions to 

ensure that the necessary emissions 

reductions occur within each covered 

state. The assurance provisions, 

described later in this section, would 

restrict EGU emissions within each state 

to the state’s budget with the variability 

limit and would ensure that every state 

is making reductions to eliminate the 

portion of significant contribution and 

interference with maintenance that EPA 

has identified in today’s action. EPA is 

proposing to impose these 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 


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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. 

To directly eliminate the portion of 

each state’s significant contribution and 

interference with maintenance that EPA 

has identified in this action, the 

proposed remedy utilizes the state 

budgets with variability limits described 

in section IV. The budgets without 

variability limits are used to determine 

the number of allowances issued to 

sources in each state. Each affected 

source must hold, and surrender to EPA, 

allowances equal to its emissions during 

the compliance period. In addition, 

assurance provisions under the 

proposed remedy cap each state’s EGU 

emissions at a state-specific budget with 

a variability limit to ensure that every 

state actually reduces, within the state, 

all emissions necessary to eliminate the 

portion of its significant contribution 

and interference with maintenance that 

EPA has identified in today’s proposal. 

For the 2012–2013 transition period, 

EPA is taking comment on whether the 

assurance provisions used to limit 

interstate trading are needed, since the 

state-specific budgets are based on 

known air pollution controls and thus a 

high level of certainty exists about 

where reductions will occur. As 

described later, the proposed FIPs 

include penalty provisions that are 

adequate to ensure that the budget 

including a variability limit will not be 

exceeded so that each state eliminates 

the portion of its significant 

contribution and interference with 

maintenance that EPA has identified in 

today’s proposed action. 

The proposed remedy establishes four 

interstate trading programs starting in 

2012: Two for annual 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 

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. 

b. How the Proposal Would Be 

Implemented 

(1) Applicability 

The requirements in the proposed 

FIPs would apply to large EGUs. 

Specifically, a covered source would be 

any stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine serving at any time, since the 

later of November 15, 1990 or the startup of the unit’s combustion device, a 

generator with nameplate capacity of 

more than 25 MWe producing electricity 

for sale. The term ‘‘fossil fuel’’ is defined 

as including natural gas, petroleum, 

coal, or any form of fuel derived from 

such material. This is the same 

definition that was used in CAIR and 

would include all material derived from 

natural gas, petroleum, or coal, 

regardless of the purpose for which such 

material is derived. For example, with 

regard to consumer products that are 

made of materials derived from natural 

gas, petroleum, or coal, are used by 

consumers and then used as fuel, these 

materials in the consumer products 

would qualify as fossil fuel. 

Certain cogeneration units or solid 

waste incinerators otherwise covered by 

this general category of covered units 

would be exempt from the FIP 

requirements. These proposed 

applicability requirements are 

essentially the same as those in the 

CAIR model trading rules and CAIR 

FIPs (reflecting the revised cogeneration 

unit definition promulgated in October 

2007 (72 FR 59195; October 19, 2007)), 

with some technical corrections to the 

exemptions. 

Cogeneration unit exemption. In order 

to meet the proposed definition of 

‘‘cogeneration unit,’’ a unit (i.e., a boiler 

or combustion turbine) must operate as 

part of a ‘‘cogeneration system,’’ which 

is defined as an integrated group of 

equipment at a source (including a 

boiler or combustion turbine, and a 

steam turbine generator) designed to 

produce useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes and electricity through 

the sequential use of energy. In order to 

qualify as a cogeneration unit, a unit 

also must meet, on an annual basis, 

specified efficiency and operating 

standards, e.g., the useful power plus 

one-half of useful thermal energy output 

of the unit must equal no less than a 

certain percentage of the total energy 

input, useful thermal energy must be no 

less than a certain percentage of total 

energy output, and useful power must 

be no less than a certain percentage of 

total energy input. Total energy input 

includes all energy input except from 

biomass. 

These proposed elements of the 

‘‘cogeneration unit’’ definition are very 

similar to the definition used in CAIR. 

However, there are two technical 

differences. First, under the definition 

used in CAIR to qualify as a 

‘‘cogeneration unit,’’ a unit had to meet 


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the efficiency and operating standards 

every year starting with the first 12- 

months during which the unit produced 

electricity. In contrast, under the 

definition proposed here, a unit can 

qualify as a ‘‘cogeneration unit’’ if it 

meets the efficiency and operating 

standards every year starting the later of 

November 15, 1990 or the date on which 

the unit first produces electricity. EPA 

believes this definition of ‘‘cogeneration 

unit’’ is preferable because it may be 

problematic to obtain sufficiently 

detailed information about unit 

efficiency and operations for some units 

(e.g., old units that may have started 

producing electricity many years ago). 

This approach is also more consistent 

with the approach taken in the general 

applicability criteria. EPA requests 

comment on whether it may also be 

problematic to obtain sufficiently 

detailed information about unit 

efficiency and operation back to 

November 15, 1990 and whether the 

efficiency and operating standards 

should be limited to even more recent 

years by requiring that the standards be 

met every year starting the later of a date 

(e.g., January 1) of a more recent year 

(e.g., 2000, 2005, or 2009) or the date on 

which the unit first produces electricity. 

Second, in CAIR, each unit had to meet 

individually the efficiency standard 

(i.e., the requirement that useful thermal 

or electrical output be at least a 

specified percentage of energy input). In 

contrast, under the ‘‘cogeneration unit’’ 

definition proposed here, if the 

cogeneration system of which a toppingcycle unit (where power is produced 

first and then useful thermal energy is 

produced using the resulting waste 

energy) is a part meets the efficiency 

standard on a system-wide basis, then 

the unit is also deemed to meet that 

efficiency standard. EPA believes this 

definition is preferable because it 

addresses cases where one unit in a 

cogeneration system is operated at a 

lower efficiency (e.g., as a ‘‘swing’’ unit 

whose use varies with demand) to allow 

the rest of the units in the cogeneration 

system to operate with higher efficiency. 

EPA requests comment on whether this 

approach should also be applied to 

bottoming-cycle units (where useful 

thermal energy is produced first and 

then useful power is produced using the 

resulting waste energy). 

As discussed previously, the 

operating and efficiency standards in 

the ‘‘cogeneration’’ definition must be 

met every year. However, EPA is 

concerned whether these annual 

standards should be applied to a 

calendar year when the unit involved 

did not operate at all. For such a year, 

the unit would be unable to meet the 

operating and efficiency standards but 

also would not have any emissions. EPA 

therefore requests comment on whether 

it should exclude, from the requirement 

to meet the operating and efficiency 

standards, calendar years (if any) during 

which a unit does not operate at all. 

If a unit meets the definition of 

cogeneration unit (including the 

efficiency and operating standards), 

then it may qualify for the proposed 

cogeneration unit exemption depending 

on whether it meets additional criteria 

concerning the amount of electricity 

sales from the unit. In order to qualify 

for the exemption, a cogeneration unit 

would need to supply in any calendar 

year—starting the later of November 15, 

1990 or the start-up of the unit’s 

combustion chamber—no more than 

one-third of its potential electric output 

capacity or 219,000 MWh, whichever is 

greater, to any utility power distribution 

system for sale. EPA requests comment 

on whether it may be problematic to 

obtain sufficiently detailed information 

about the disposition of a unit’s 

generation (e.g., how much was used on 

site or by an industrial host and how 

much was supplied to a utility 

distribution system for sale) back to 

November 15, 1990 and whether the 

electricity sales limit should be 

restricted to more recent years by 

requiring that the limit be met every 

year starting the later of a date (e.g., 

January 1) of a more recent year (e.g., 

2000, 2005, or 2009) or the start-up of 

a unit’s combustion chamber. 

Solid waste incineration unit 

exemption. The proposed FIPs also 

include an exemption for solid waste 

incineration units commencing 

operation before January 1, 1985, for 

which the average annual fuel 

consumption of non-fossil fuels during 

1985–1987 exceeded 80 percent and, 

during any three consecutive calendar 

years after 1990, the average annual fuel 

consumption of non-fossil fuels exceeds 

80 percent, on a Btu basis. With regard 

to a solid waste incineration unit 

commencing operation on or after 

January 1, 1985, EPA proposes that the 

unit would be exempt if its average 

annual fuel consumption of non-fossil 

fuel for the first 3 calendar years of 

operation and for any 3 consecutive 

calendar years, thereafter, does not 

exceed 80 percent. This is the same as 

the solid waste incineration unit 

exemption used in CAIR. EPA requests 

comment on whether it may be 

problematic to obtain sufficiently 

detailed information about unit 

operation potentially as far back as 

1985–1987 and 1990 and whether the 

fuel consumption standard for each unit 

should be limited to more recent years 

by requiring that the standard be met 

every year starting the later of a date 

(e.g., January 1) of a more recent year 

(e.g., 2000, 2005, or 2009) or the date on 

which the unit first produces electricity. 

Further, analogous to the approach 

proposed for the cogeneration unit 

exemption, the proposed solid waste 

incineration unit exemption would 

apply to units that qualify as solid waste 

incineration units every year starting the 

later of November 15, 1990 or the date 

the unit first produces electricity. EPA 

requests comment on whether it may be 

problematic to obtain sufficiently 

detailed information about whether a 

unit qualified as a solid waste 

incineration unit back to November 15, 

1990 and whether the qualification 

requirement should be restricted to 

more recent years by imposing the 

qualification requirement every year 

starting the later of a date (e.g., January 

1) of a more recent year (e.g., 2000, 

2005, or 2009) or the date of unit first 

produces electricity. 

EPA also proposes to make explicit in 

the FIPs an interpretation that the 

Agency adopted in applying CAIR, 

namely that—solely for purposes of 

applying the fossil-fuel use limitation in 

the solid waste incineration unit 

exemption—the term ‘‘fossil fuel’’ is 

limited to natural gas, petroleum, coal, 

or any form of fuel derived from such 

material ‘‘for the purpose of creating 

useful heat.’’ For example, this means 

that consumer products made from 

natural gas, petroleum, or coal are not 

fossil fuel, for purposes of determining 

qualification under the limitation on 

fossil-fuel use, because the products 

(e.g., tires) were derived from natural 

gas, petroleum, or coal in order to meet 

certain consumer needs (e.g., to meet 

transportation needs), not in order to 

create fuel (i.e., material that would be 

combusted to produce useful heat). 

Opt-in units. EPA proposes to 

include, in the trading programs under 

the proposed FIP, provisions allowing 

non-electric generating (non-covered) 

units to opt into one or more of the 

proposed trading programs. EPA is 

proposing opt-in provisions since they 

could encourage emission reductions by 

sources that could make lower cost 

emissions reductions than electric 

generating units. These lower cost 

reductions could replace higher cost 

reductions that would otherwise be 

required by some electric generating 

units and could reduce overall program 

costs. 

Specifically, the proposed opt-in 

provisions would allow a non-covered 

unit to enter a proposed trading program 

voluntarily and obtain an allocation of 


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allowances reflecting the unit’s 

emissions before opting in. Once in the 

program, the unit could make emissions 

reductions at a lower cost than other 

units in the program and then sell, to 

covered sources for use in compliance, 

allocated allowances that are in excess 

of the unit’s reduced emissions. The 

allowances created for and allocated to 

the opt-in unit would be in addition to 

the allowances issued from the state 

budget and would be usable in 

compliance by any covered unit (or optin unit) just like the allowances 

allocated from the state budget to 

covered sources. Replacing higher cost 

reductions by covered units by lower 

cost reductions by opt-in units could 

reduce the overall cost of controlling 

emissions. EPA requests comment on 

the benefits and concerns of including 

opt-in provisions. 

The proposed opt-in provisions 

would establish the following 

procedures, which are similar to those 

set forth in the CAIR FIPs. A unit would 

be eligible to opt into one of the 

proposed trading programs if the unit: 

(1) Is an operating boiler, combustion 

turbine, or other stationary combustion 

device; (2) is in a facility that is located 

in a state subject to that proposed 

trading program; (3) vents all its 

emissions through a stack or duct; and 

(4) would be able to meet the 

monitoring, reporting, and 

recordkeeping requirements for covered 

units under the proposed trading 

program. The owners and operators, 

through a designated representative, of 

a source with a unit seeking to opt in 

would submit to EPA an opt-in 

application, which must include an 

emissions monitoring plan for the unit. 

If EPA approved the monitoring plan, 

the unit would operate, monitor, and 

report emissions in accordance with the 

monitoring plan and monitoring and 

reporting requirements under Part 75, 

for at least one or for up to 3 full 

calendar years (or full ozone seasons, in 

the case of an opt-in unit in the 

proposed NOX ozone season trading 

program). The unit’s monitored heat 

input and emissions rate for that period 

would be the baseline heat input and 

baseline emissions rate used in 

calculating any future opt-in allowance 

allocations. 

After the monitoring period, EPA 

would review the opt-in application and 

either approve the application 

(including an allowance allocation for 

the first year of approved opt-in status), 

effective January 1 (May 1 for the NOX

ozone season program) of the year of the 

approval, or disapprove the application. 

By December 1 (September 1 for the 

NOX ozone season program) of the first 

year and each subsequent year, EPA 

would calculate and record the opt-in 

unit’s allowance allocation for the year. 

The allowance allocation for the year 

involved would be the product of: The 

lesser of the baseline heat input and the 

opt-in unit’s actual heat input during 

the control period in the immediately 

preceding year; and the lesser of the 

baseline emissions rate multiplied by 70 

percent and the most stringent state or 

federal emissions limitation applicable 

to the unit (or emissions levels resulting 

from the imposition of Clean Air Act 

requirements) any time during the 

control period in the year involved. 

After the opt-in unit was in the 

program for at least four years, the 

owners and operators could request to 

withdraw the opt-in unit at the end of 

a control period if the unit met the 

requirement to hold allowances 

covering emissions for that control 

period and if any allowances already 

allocated for a subsequent control 

period were surrendered. However, the 

owners and operators could not submit 

a new opt-in application for the 

withdrawn unit until at least 4 years 

after the last control period before the 

withdrawal. An opt-in unit that had a 

change in regulatory status during a 

control period and would then meet the 

general applicability requirements for 

covered units would immediately lose 

its status as an opt-in unit. Having lost 

its opt-in unit status, the unit would 

have to surrender to EPA the allocated 

opt-in allowances attributable to the 

portion of any control period during 

which the unit no longer qualified as an 

opt-in unit. 

In addition to a general request for 

comment on all aspects of this opt-in 

requirement, EPA requests comment on 

three specific aspects of the proposed 

opt-in provisions. First, EPA requests 

commenters to explain how much 

interest they believe owners and 

operators of noncovered sources would 

have in using these proposed provisions 

to opt into one or more of the proposed 

trading programs and what types of 

sources would be most likely to opt in. 

Commenters on this aspect of the 

proposed provisions should consider 

what effect (if any) future emission 

reduction requirements under 

upcoming, new regulations (e.g., 

regulations concerning maximum 

available control technology (MACT) 

standards for sources such as industrial 

boilers and cement kilns, best available 

retrofit technology (BART) requirements 

for certain stationary source categories, 

and reasonably available control 

technology (RACT)) might have on the 

pool of sources that might be interested 

in opting into the program. EPA notes 

that, in the Acid Rain Program, opt-in 

provisions were established in section 

410 of the Act, were implemented in the 

Acid Rain Program regulations starting 

in 1995, and, to date, have been used by 

4 facilities (plus 2 more facilities that 

temporarily opted in to obtain 

allowances for use in the CAIR SO2

trading program). In the NOX Budget 

Trading Program, EPA promulgated optin provisions that states could include 

in their SIPs and that were used by 

3 facilities. 

Second, EPA requests comment on 

whether it is necessary to take steps to 

identify in this application process 

whether emissions reductions identified 

by these facilities are reductions units 

would not have made for other reasons 

unrelated to the opt in. Comments on 

this issue would be especially useful if 

they discussed how the proposed opt-in 

provisions could be revised in order to 

ensure that opt-in units would not be 

credited for emissions reductions that 

the units would make even if they did 

not opt in. For example, a unit that, for 

business or other reasons, was already 

planning to take actions that would 

have the effect of reducing emissions 

(e.g., fuel switching) may be able to opt 

in under this proposed approach and 

obtain allowance allocations that could 

be sold to covered units. In that case, 

emissions reductions that would have 

occurred anyway would be offset by the 

allocation of new, opt-in allowances 

that would be in addition to the state 

budget. The net result, in that case, 

would be an increase in total 

emissions—considering the emissions of 

both the covered units and the opt-in 

unit—over what total emissions would 

have been if the unit had not opted in. 

EPA requests comment on whether, in 

that circumstance the total emissions 

reduction still may be sufficient to 

satisfy the interstate transport issue if 

such reductions were not anticipated in 

state budgets. In other words, even if 

emissions reductions would have 

happened in the absence of the program, 

they may still be reductions that 

alleviate attainment or maintenance 

issues in downwind states. Third, EPA 

requests comment on whether the 

baseline emission rate used to 

determine the allocations for each optin unit should be multiplied by 70 

percent before EPA compares that rate 

to the unit’s most stringent applicable 

emissions limitation in order to 

determine which is lower. The lower 

emission rate would then be used in 

calculating the opt-in unit’s allocation. 

EPA also requests comment on whether 

the allocation for an opt-in unit during 

Phase II of the proposed SO2 Group 1 


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85Planned units, as identified in the EGU 

inventory and included in IPM modeling 

projections, comprise units that had broken ground 

or secured financing and were expected to be online 

by the end of 2011. 

trading program should be reduced by 

45 percent, reflecting the average 

percent reduction in state SO2 Group 1 

budgets from Phase I to Phase II. The 

70 percent reduction of the baseline 

emission rate for all opt-in units, and 

the further 45 percent reduction in 

Phase II allocations for SO2 Group 1 optin units, would be meant to ensure that 

opt-in facilities install controls in a 

similar manner as covered units; 

however, all things equal, this may 

serve to lower the number of facilities 

that would opt into the program. EPA 

therefore specifically solicits comment 

on whether the proposed 70 percent 

reduction (or some other percentage 

reduction or no reduction) should 

applied to the baseline emission rate for 

all opt-in units and on whether any 

additional percentage reduction or 

45 percent or some other additional 

percentage reduction should be applied 

to SO2 Group 1 opt-in units on Phase II 

in order to strike a reasonable balance 

between achieving additional 

reductions per opt-in facility and having 

more facilities opt in. 

Sources equal to or less than 25 MWe 

and Non-EGUs. Certain smaller EGUs 

and non-EGU sources that were 

included in the 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-than25 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). 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 

these allowance-holding requirements at 

the source (i.e., facility) level. 

This section explains how EPA 

proposes to allocate to two sets of units 

in a state, existing units and new units. 

This section also describes the new unit 

set asides in each state, allocations to 

units that are not operating, and the 

recording of allowance allocations in 

facility accounts. 

EPA proposes to base allocations to 

existing units on projected emissions 

from these units after elimination of 

some or all significant contribution and 

interference with maintenance (i.e., 

projected emissions after 

implementation of the proposed FIPs), 

and after deductions for the new unit set 

asides. Section IV.E describes how EPA 

developed the overall state budgets. 

EPA requests comment on all aspects 

of the allocation method, such as the 

overall state budgets, the need to have 

existing unit and new unit allowance 

allocations, the proposed allocation 

methodology for existing units, and the 

proposed allocation methodology for 

new units. EPA believes the proposed 

approach is consistent at the state 

budget and unit level with the Court’s 

direction and also addresses the new 

unit issue. The proposed methodology 

for allocating allowances does not 

consider heat input or fuel adjustment 

factors. Note that in light of the Court 

decision, EPA also is not proposing any 

allocation methodologies that rely on 

Title IV existing allowances. 

EPA requests comment on whether 

there are alternative allocation methods 

EPA should consider that are consistent 

with the Court decision. EPA asks that 

commenters present any such 

approaches in detail to enable thorough 

evaluation and that they provide a legal 

analysis demonstrating how the 

approach is consistent with the Court’s 

opinions and the statutory mandate of 

section 110(a)(2)(D). 

Allocations to existing units. Existing 

units are units, as described in the 

Applicability section, previously (see 

4.b), that commenced commercial 

operation, or are planned 85 to 

commence commercial operation, prior 

to January 1, 2012. EPA proposes that, 

for 2012, each existing unit in a given 

state receives allowances commensurate 

with the unit’s emissions reflected in 

whichever total emissions amount is 

lower for the state, 2009 emissions or 

2012 base case emissions projections. In 

either case, the allocation is adjusted 

downward, if the unit has additional 

pollution controls projected to be online 

by 2012. EPA proposes to use this same 

method to allocate allowances for each 

of the four trading programs (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. 

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 


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86 If a unit was allocated allowances but turned 

out not to be a covered unit or turned out not to 

be required to hold allowances as of January 1, 

2012, then the treatment of the allocation depends 

on when the Administrator determines the unit is 

not subject to the trading program or to the 

allowance-holding requirement. For instance, if the 

allocation has not been recorded, the Administrator 

would not record it, and, if the allocation has been 

recorded and the Administrator has not completed 

the compliance determination process for the unit, 

allowances equal to the allocation would be 

deducted from the unit’s compliance account. 

Rule cap and trade programs commence 

(see discussion of schedule, later). The 

allocations generally would 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 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 unit, or turned out not to be 

required to hold allowances to cover 

emissions, as of the first day of the 

control period in 2012,86 or if the unit 

stops operating for three consecutive 

years. 

Allocations to new units. EPA 

proposes to allocate emissions 

allowances to new units from new unit 

set-asides in each state. EPA proposes, 

for each of the four trading programs, to 

define a new unit as: Any covered EGU 

not listed in the table in Appendix A of 

the trading rule applicable to that 

program; any unit listed in Appendix A 

whose allocation is subject to the 

requirement that the Administrator not 

record the allocation or that the 

Administrator deduct the amount of the 

allocation (see previous discussion in 

footnote), or any unit listed in Appendix 

A that stopped operating for three 

consecutive years, is no longer allocated 

allowances as an existing unit, but 

resumes operation. 

EPA believes it is important to have 

a small new unit set-aside in each state 

to cover new units within the budget 

that was set aside to address the state’s 

significant contribution and interference 

with maintenance. To create new unit 

set-asides, EPA would distribute to 

existing EGUs a quantity of allowances 

less than the entire state emissions 

budgets. EPA would hold back, for the 

new unit set-aside for a state, 3 percent 

of the state budget. Three percent was 

established based on the total amount of 

new unit emissions projected for all the 

covered states (See ‘‘State Budgets, Unit 

Allocations, and Unit Emissions Rates’’ 

TSD). In this way, new units could be 

allocated some allowances for their 

emissions, which are part of the the 

state’s contribution to downwind 

nonattainment or interference with 

maintenance. 

For every control period after the 

control period in which a new unit 

commences commercial operation or, in 

the case of an existing unit that did not 

operate for three consecutive years, 

resumes operation, EPA would allocate 

to the unit from the new unit set-asides 

based on the unit’s reported emissions 

from the previous control period. EPA 

would not allocate to a new unit for the 

control period during which the unit 

commences commercial operation 

because the unit would have no actual 

emissions data on which to base such an 

allocation. 

EPA proposes that, for the first control 

period for which the new unit wants an 

allowance allocation from the new unit 

set aside (after the first year of 

operation), the designated 

representative of the source that 

includes the new unit would submit to 

EPA a request for a new unit allocation. 

For each control period, any 

allowances remaining in a state’s new 

unit set-aside (after allocations are made 

to new units that requested allowances) 

would be distributed to the existing 

units in that state in proportion to the 

existing unit’s original allocations. This 

ensures that total allocations to units in 

the state would equal the state budget. 

For each control period, if the size of 

the new unit set-aside were insufficient 

to provide allocations for all new units 

requesting allowances, then allocations 

to all new units would be proportionally 

reduced. 

EPA requests comment on the 

proposed allocation approach for new 

units. EPA also requests comment on 

alternative allocation approaches that 

would provide allowances to new units 

for the control period during which the 

unit commences commercial operation. 

Size of new unit set asides. EPA 

proposes new unit set-asides that are 

3 percent of the state emissions budgets. 

The size of the new unit set-aside would 

be 3 percent for the 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 set-asides on a 

comparison of projected emissions from 

new units to projected emissions from 

existing units for all covered states 

under the proposed State Budgets/ 

Limited Trading remedy. As noted 

previously, EPA proposes that after a 

unit is not operating for three 

consecutive years, the allowances that 

would otherwise have been allocated to 

that unit, starting in the seventh year 

after the first year of non-operation, 

would be allocated to the new unit setaside for the state in which the retired 

unit is located. This approach would 

allow the size of the new unit set-asides 

to grow over time. Note that in EPA’s 

analysis to determine the size of the 

new unit set-asides, EPA assumed that 

allocations for non-operating units 

would be allocated to the new unit setasides after a unit had ceased operating 

for 3 consecutive years (see ‘‘State 

Budgets, Unit Allocations, and Unit 

Emissions Rates’’ TSD). EPA requests 

comment on the size of the new unit setasides. 

Non-operating units. EPA proposes 

that, once an EGU does not operate (i.e., 

does not combust any fuel) for 3 

consecutive years, the Agency would no 

longer allocate allowances to the unit, 

starting in the seventh year after the first 

year of non-operation. All allowances 

that would otherwise have been 

allocated to the unit for that seventh 

year and every year thereafter would be 

allocated to the new unit set-aside for 

the state in which the non-operating 

unit is located. This would provide 

additional allowances for new units that 

may need them (e.g., for new units that 

replace non-operating units), and 

reflects the fact that new unit emissions 

are included in the state’s budget that 

eliminates the portion of significant 

contribution and interference with 

maintenance that EPA has identified in 

today’s proposed action (in an average 

year). 

EPA proposes to continue allocating 

allowances to non-operating 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 


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immediately discontinuing allocations 

to such units upon the unit ceasing 

operation. 

Continuing allocations to nonoperating units has the benefit of 

reducing the incentive to keep units in 

operation that should otherwise be, for 

instance, permanently retired due to age 

and inefficiency. EPA believes there 

will be less incentive to continue 

running old, inefficient EGUs if at least 

some allowances would still be received 

after retirement. On the other hand, 

stopping allocations for non-operating 

units realigns allowance allocations 

with the sources that actually need such 

allowances. Non-operating units 

obviously are no longer emitting and so 

do not need allowances. Moreover, 

additional allowances may be needed 

for the new unit set-aside to 

accommodate new units coming on line 

in the future. Allocating allowances for 

a specified, but limited, period after the 

unit ceases operating for 3 consecutive 

years, as EPA proposes to do, would be 

a middle ground approach to this issue. 

EPA requests comment on the 

proposed approach for allocating 

allowances to non-operating units. EPA 

requests comment on simplifying 

allocations by not allocating at all to 

non-operating units. EPA also requests 

comment on maintaining perpetual 

allocations to non-operating units, 

similar to the treatment of non-operating 

units in the title IV Acid Rain Program. 

Schedule for determining and 

recording allowances. As discussed 

previously, proposed allocations for 

existing units are shown in the ‘‘State 

Budgets, Unit Allocations, and Unit 

Emissions Rates’’ TSD. EPA proposes to 

include final allocations for existing 

units in the Appendix A for each 

proposed trading program in the final 

Transport Rule. 

EPA proposes to record initial 

allowances for existing units in facility 

accounts by September 1, 2011, for the 

control periods in 2012, 2013, and 2014. 

EPA proposes to record allowances for 

existing units by July 1, 2012 and July 

1 of each year thereafter, for the control 

periods in the third year after the year 

the allowances are recorded. For 

example, EPA would record existing 

unit allowances by July 1, 2012 for 

control periods in 2015. Recording 

allowances several years in advance 

supports the development of the 

allowance trading markets and provides 

time for covered sources to plan for 

compliance. 

As discussed previously, EPA 

proposes to determine allocations to a 

new unit based on the unit’s reported 

emissions the prior year. Although the 

last quarter of emissions data for a year 

must be submitted to EPA in the fourth 

quarterly emissions report by January 30 

of the next year, the emissions data in 

that report may be revised based on 

EPA’s review and may not be finalized 

until May or June after receipt of that 

report. Consequently, EPA proposes to 

determine new unit allocations by July 

1 of the year for which the allocation is 

determined. (Because, for an ozone 

season ending September 30, emissions 

data may not be finalized until the 

following February or March, EPA 

proposes to determine new unit 

allocations by April 1.) For example, 

EPA would determine a new unit’s 

allocations for control periods in 2012 

by July 1, 2012. EPA proposes to make 

the new unit allocation determinations 

available to the public through a notice 

of data availability. Under the proposal, 

objections to the notice could be 

submitted, and EPA would issue a 

second notice of data availability 

referencing any necessary adjustments 

of the new unit allocations. 

EPA proposes to record allowances 

for new units by September 1, 2012 and 

September 1 of each year thereafter, for 

the control periods in the year that the 

allowances are recorded. (For the units 

in the 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 

other alternative allocation methods. 

One is discussed here, but EPA 

recognizes that there are many ways that 

allowances could be allocated. EPA is 

requesting comment on whether the 

alternative described here or any other 

approach should be used instead of the 

proposed allocation method. 

As discussed in section IV, the state 

emissions budgets are determined based 

on EPA’s analysis of significant 

contribution and interference with 

maintenance in each upwind state. EPA 

believes that it is appropriate to develop 

individual unit allowances consistent 

with this approach. In the proposed 

approach, EPA does this by allocating 

down to the individual unit level using 

all of the same assumptions used in 

developing the proposed budgets. Under 

this approach all units are allocated 

allowances consistent with their 

projected emissions; this means that a 

unit that installs control equipment 

receives fewer allowances than a similar 

unit that did not install control 

equipment. 

EPA is taking comment on an 

alternative methodology that still links 

unit allowances directly to the way state 

budgets were developed (and thus, 

significant contribution was defined). In 

the alternative, all units within a state 

would be treated as a single group. The 

allocation method would distribute 

allowances equal to a state’s emissions 

budget without variability to each 

covered source in the state (in effect, 

distributing the responsibility for 

eliminating significant contribution and 

interference with maintenance) based 

on each source’s proportional share of 

total state heat input. The state heat 

input would be as projected for the 

initial year of the program. In other 

words, this alternative method for 

distributing allowances would have the 

effect of distributing the responsibility 

for eliminating all or part of a state’s 

overall significant contribution and 

interference with maintenance to 

individual units based on each unit’s 

share of projected heat input. 

There are other approaches to 

allocation. For example, EPA could 

identify groups of units in each state 

that are capable of having similar 

emissions characteristics (e.g., grouped 

by size, fuel type, or age). EPA would 

distribute a state’s emissions budget 

without variability to each group of 

units in the state (in effect, distributing 

the responsibility for eliminating all or 

part of significant contribution) perhaps 

based on each group’s proportional 

share of the state budget as projected in 

the initial year of the program. After 

apportioning a state’s budget to the 

groups of units, under such an approach 

EPA could distribute allocations to 

individual sources within each group 

based on each source’s proportional 

share of projected heat input. Like the 

first alternative allocation method 

described previously, this approach 

distributes each state’s significant 

contribution and interference with 

maintenance to individual sources in 

the state. By determining groups and 

then distributing allocations within the 

groups based on proportional shares, 

this approach would treat units within 

the categories equally (i.e., it would not 

treat a source that had acted early to 

control differently from one that had yet 

to take control action). 


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EPA requests comment on the 

proposed allocation approach, the 

alternative approach, and on any other 

approaches that are consistent with the 

Court decision. EPA asks that 

commenters present any such 

approaches in detail to enable thorough 

evaluation and that they provide a legal 

analysis demonstrating how the 

approach is consistent with the Court’s 

opinions and the statutory mandate of 

section 110(a)(2)(D). 

(3) Allowance Management System 

EPA proposes that the State Budgets/ 

Limited Trading remedy include an 

allowance management system (AMS) 

operated essentially the same as the 

existing allowance management systems 

that are currently in use for CAIR and 

the Acid Rain Program under Title IV. 

Under the proposed State Budgets/ 

Limited Trading remedy, the 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 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. Most 

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 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 sufficient time to 

complete installation and certification 

of monitoring systems without having to 

request extensions of time and would 

facilitate compliance by making the 

monitoring deadline clearer for owners 

and operators and easier for EPA to 

apply. See a discussion on units 

transitioning from CAIR and units 

previously not covered by Part 75 

requirements in section V.F, later. 

EPA also proposes to require 

designated representatives to submit 

quarterly reports that would include 

emissions and related data and proposes 

to establish a procedure for 

resubmission of quarterly reports where 

appropriate. Specifically, the proposed 

reporting provisions would include the 

same requirement to submit quarterly 

reports as the requirement in Part 75. In 

addition, the proposed provisions 

would include language that would 

make explicit a process that is implicit 

under, and has been in continuous use 

in, the Acid Rain, NOX Budget, and 

CAIR trading programs. The 

resubmission process would be as 

follows. The Administrator could 

review and audit any quarterly report to 

determine whether the report met the 

monitoring, reporting, and 

recordkeeping requirements in the 

proposed rule and Part 75. The 

Administrator would provide 

notification to the designated 

representative stating whether any of 

these requirements was not met and 

specifying any corrections that the 

Administrator believed were necessary 

to make through resubmission of the 

report and a reasonable deadline for a 

response. The Administrator could 

provide reasonable extensions of such 

deadline. The designated representative 

would be required, within the deadline 

(including any extensions), to resubmit 

the report with the identified 

corrections, except to the extent the 

designated representative would submit 

information showing that a correction 

was not necessary because the report 

already met the monitoring, reporting, 

and recordkeeping requirements 

relevant to the correction. Any 

resubmission of a quarterly report 

would have to meet the requirements for 

quarterly report submission, except for 

the deadline for initial submission of 

quarterly reports. 

(5) Assurance Provisions 

To ensure that the proposed FIPs 

require the elimination of all emissions 

that EPA has identified that 

significantly contribute to 

nonattainment or interfere with 

maintenance within each individual 

state, we are proposing to establish 

assurance provisions, as described later, 

in addition to the requirement that 

sources hold allowances sufficient to 

cover their emissions. These assurance 

provisions limit emissions from each 

state to an amount equal to that state’s 

budget with the variability limit for state 

budgets, discussed in section IV. As 

described therein, this variability limit 

takes into account the inherent 

variability in baseline EGU emissions 

and recognizes that state emissions may 

vary somewhat after all significant 

contribution is eliminated. This 

approach also provides sources with 

flexibility to manage growth and electric 

reliability requirements, thereby 

ensuring the country’s electric demand 

will be met while meeting the statutory 

requirement of eliminating significant 

contribution. 

Starting in 2014, EPA is proposing as 

part of the FIPs to establish limits on the 

total emissions that may be emitted 

from EGUs at sources in each state. For 


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any single year, the state’s emissions 

must not exceed the state budget with 

the variability limit allowed for any 

single year for that state (i.e., the state’s 

1-year variability limit). In addition, the 

3-year rolling average of the state’s 

emissions must not exceed the state 

budget with the variability limit allowed 

on average for any consecutive 3 years 

for that state (i.e., the state’s 3-year 

variability limit). Note that in 2014 and 

2015, EPA would apply only the 1-year 

variability limit, and not the 3-year 

variability limit. Because emissions 

would be evaluated against the 3-year 

variability limit on a 3-year rolling 

average basis, the application of the 

3-year variability limit in 2016 would 

serve to limit emissions in 2014 and 

2015. 

In other words, in addition to covered 

sources being required to hold 

allowances sufficient to cover their 

emissions, the total sum of EGU 

emissions in a particular state cannot 

exceed the state budget with the state’s 

1-year variability limit in any one year, 

and the state’s annual average emissions 

for any 3-year period can not exceed, on 

average, the state budget with the state’s 

3-year variability limit. The fact of the 

3-year variability limit would further 

assure that emissions are constrained 

during the two preceding years. 

For example, a hypothetical state has 

a budget of 100,000 tons, a 1-year 

variability limit of 10,000 tons, and a 

3-year variability limit of 5,800 tons. 

• In the first year, collective 

emissions from covered EGUs in the 

state are 120,000 tons, 10,000 tons over 

the budget with 1-year variability limit 

of 110,000 tons, triggering the assurance 

provisions in that year. 

• In the second year, collective 

emissions from covered EGUs in the 

state are 97,500 tons, below the state 

budget with 1-year variability limit of 

110,000 tons. Assurance provisions are 

not triggered. 

• In the third year, collective 

emissions from covered EGUs in the 

state are 109,000 tons, below the state 

budget with 1-year variability limit of 

110,000 tons. Assurance provisions are 

not triggered for the 1-year variability 

limit. But after three years, the state 

emissions are computed against the 

3-year variability limit. The 3-year 

rolling average (adding the last 3 years 

of emissions and dividing that by three) 

computes to 108,833 and determines 

that the 3-year variability limit of 

105,800 tons is exceeded, even though 

in any one year, the 1-year variability 

limit may not have been exceeded. 

• In the fourth year, collective 

emissions from covered EGUs in the 

state are 99,000 tons, below the state 

budget with 1-year variability limit of 

110,000 tons. Assurance provisions are 

not triggered for the 1-year variability 

limit. The 3-year rolling average of the 

last 3 years is 101,833, which is less 

than the 3-year variability limit of 

105,800. Assurance provisions are not 

triggered for the 3-year variability limit. 

The variability limits for each state 

are shown in Tables IV.F–1 through 

IV.F–3 in section IV. The basis for the 

variability limits is also described in 

section IV.F. Additional details may be 

found in the ‘‘Power Sector Variability’’ 

TSD in the docket to this rule. 

To implement this requirement, EPA 

would first evaluate whether any state’s 

total EGU emissions in a control period 

exceeded the state’s budget with 1-year 

variability limit. Next, EPA would 

evaluate whether any state’s total EGU 

emissions in a control period exceeded 

the state’s budget with the 3-year 

variability limit (once the program is in 

effect for 3 years, and each year 

thereafter). If any state’s EGU emissions 

in a control period exceeded either of 

these limits, then EPA would apply 

additional criteria to determine which 

source owners in the state would be 

subject to an allowance surrender 

requirement. The proposed allowance 

surrender requirement that owners 

surrender allowances under the 

assurance provisions would be triggered 

only for owners of units in a state where 

the total state EGU emissions for a 

control period exceed the applicable 

state budget with the variability limit. 

Moreover, only an owner whose units’’ 

emissions exceed the owner’s share of 

the state budget with the variability 

limit would be subject to the allowance 

surrender requirement. 

In applying the additional criteria, 

EPA would evaluate which source 

owners in the state had emissions 

exceeding the respective owner’s share 

of the state budget with the variability 

limit (regardless of whether the source 

had enough allowances to cover its 

emissions). An owner’s share would 

equal the sum of the allocations of its 

EGUs in the state, plus its proportional 

share of the amount of the variability 

limit that, when included with the state 

budget, was exceeded by the state’s EGU 

emissions during the year involved. If 

the state emissions exceeded both the 

state budget with the 1-year and with 

the 3-year variability limit, then the 3- 

year variability limit would be used in 

determining the owner’s share of the 

state budget. 

On the other hand, if the state’s total 

EGU emissions for a control period in a 

given year did not exceed the state 

budget with the state’s 1-year variability 

limit and did not exceed, on a 3-year 

rolling average basis, the state budget 

with the state’s 3-year variability limit, 

then the additional criteria concerning 

the emissions of each owner’s sources in 

the state would not apply. For more 

details see subsection V.D.4.i, later, and 

the rule text at the end of this preamble 

(§§ 97.425, 97.525, 97.625, and 97.725— 

Compliance with assurance provisions). 

As discussed previously, EPA would 

not allocate emissions allowances to a 

new unit for the control period during 

which the unit commences commercial 

operation. In the case where assurance 

provisions for a state are triggered in the 

year that a new unit first operates, the 

owner’s share—if calculated as the sum 

of the allocations of its EGUs plus its 

proportional share of the variability 

limit—would necessarily be zero 

because the new unit would have no 

allocation for that year. Instead, EPA 

would use a specific surrogate 

emissions number to calculate the 

maximum amount the unit could emit 

in that year before being required to 

surrender allowances under the 

assurance provisions. The surrogate 

emissions number would apply only if 

the state’s assurance provisions were 

triggered and only in the first year of the 

new unit’s operation. 

The surrogate emissions number 

would be calculated by multiplying the 

unit’s allowable emissions rate (in lbs/ 

MWe) by the unit’s maximum hourly 

load (in MWe/hr) and a default capacity 

factor specific to the unit type. The 

default capacity factors would be: 84 

percent for coal-fired units, 66 percent 

for gas-fired combined cycle units, and 

15 percent for combustion turbines in 

the 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 coal-fired units 

commencing operation since 2000 and 

combustion turbines since 2004. EPA 

believes that this approach would cover 

a range of operating conditions for new 

units and thus avoid attributing to each 

new unit a share of the state budget with 

variability reflecting the maximum 

amount of emissions possible for the 

unit in its first operating year, in the 

case where the state’s assurance 

provisions were triggered. (See 

‘‘Capacity Factors Analysis for New 

Units’’ TSD in the docket for further 

information on the proposed default 

capacity factors for new units). 


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45314 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

87U.S. Environmental Protection Agency (U.S. 

EPA). 2002. Engineering and Economic Factors 

Affecting the Installation of Control Technologies 

for Multipollutant Strategies. Washington, DC. 

These assurance provisions are above 

and beyond the fundamental 

requirement for each source to hold 

enough allowances to cover its 

emissions in the control period. Failure 

to hold enough allowances to cover 

emissions is a violation of the CAA, 

subject to an automatic penalty and 

discretionary civil penalties, as 

described later. 

EPA believes the likelihood of 

triggering assurance provisions is low. 

The State Budgets/Limited Trading 

programs have a regional cap that limits 

overall emissions; state-specific budgets 

that are the basis for allocating 

emissions allowances in each state; 

assurance provisions that each state 

eliminates the excess emissions leading 

to significant contribution and 

interference with maintenance that EPA 

has identified in this proposed action; 

and additional allowance surrender 

requirements for not meeting emissions 

reductions requirements. As discussed 

in section e, later, the underlying 

mechanism of cap and trade, even 

without assurance provisions, has 

succeeded in reducing emissions below 

allowance levels. The accumulated data, 

history, and experience from these 

programs underscore that emissions 

reductions requirements and 

environmental and public health goals 

of the programs were met. However, 

unlike earlier cap and trade programs 

(e.g., the Acid Rain, CAIR, and 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 limit. An example of a 

circumstance that might result in 

emissions approaching the variability 

limit is an extended nuclear unit outage 

that causes a company to run its fossil 

units harder to meet demand. Increased 

emissions under such a scenario would 

not result from the ability to trade across 

state boundaries, or because the fossil 

units were not controlled, but because 

the units were operated more. In this 

type of scenario, emissions would also 

be higher in a rate-based program that 

did not allow interstate trading. 

EPA is setting two criteria to 

determine if a state has exceeded its 

budget using the state budget with the 

1-year variability limit on an annual 

basis, and the state budget with the 

3-year variability limit on a 3-year 

rolling average basis. EPA proposes that 

emissions from an owner’s EGUs in 

excess of the owner’s share of the state 

budget with the variability limit would 

not be a violation of the regulation or 

the CAA. But the owner would be 

required to make an allowance 

surrender of one allowance for each ton 

emitted over the owner’s proportional 

share of the amount by which state 

emissions exceed the state budget with 

the variability limit. 

This allowance surrender requirement 

is significant, and EPA believes 

sufficient, to ensure that the state 

emissions will not exceed the budgets 

plus the variability limit. The allowance 

surrender requirement, however, is less 

severe than the penalties (discussed 

later) that apply if a source fails to 

comply with the requirement to hold an 

allowance for each ton emitted by EGUs 

at the source. However, failing to hold 

sufficient allowances to meet the 

allowance surrender requirement would 

be a violation of the regulations and the 

CAA. 

EPA requests comment on whether 

the allowance surrender requirement 

should be different (either more or less) 

than one allowance per ton emitted over 

the owner’s proportional share of the 

state budget with the variability limit. In 

addition, EPA requests comment on 

whether the exceedance of total 

emissions by an owner’s sources over 

the owner’s share of the state budget 

with the variability limit should be a 

violation of the CAA and thus subject to 

discretionary penalties. Finally, EPA 

requests comment on all aspects of the 

proposed assurance provisions in the 

proposed FIPs. 

(6) Penalties 

All covered sources must hold an 

allowance for each ton of SO2 or NOX

emitted and are subject to penalties if 

they fail to comply with this allowanceholding requirement. 

Each source must hold in its 

compliance account in the AMS enough 

allowances issued for the respective 

annual trading program (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 

For the 2012–2013 transition period, 

EPA is proposing the State Budgets/ 

Limited Trading remedy without the 

previously-described assurance 

provisions (penalty provisions would 

remain in effect), but taking comment 

on whether the assurance provisions 

should be in force during that period. 

New state-specific control budgets 

(developed as described in section IV) 

and new allowances would be allocated 

to sources in the Transport Rule region. 

These state budgets would reflect the 

operation of all existing and planned 

emission control devices. Under EPA’s 

proposed approach, for 2012 and 2013, 

intrastate and interstate trading, without 

the assurance provisions, would be 

allowed. 

The locations of existing and planned 

air pollution control retrofits on EGUs 

are known, and this knowledge provides 

greater certainty of where reductions 

will occur and how these reductions 

should impact air quality in downwind 

areas. There would not be sufficient 

time to complete construction of 

additional control retrofits or entirely 

new, controlled EGUs before 2014.87

Consequently, EPA believes that there 

is a high level of certainty that 

emissions reductions projected for 


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2012–2013 with interstate trading 

would be achieved within the states 

where they are projected to occur, 

making imposition of the assurance 

provisions during 2012–2013 

unnecessary. In addition, EPA believes 

that the two alternative options 

discussed later present greater 

implementation challenges than this 

proposed interim remedy for 2012– 

2013. See sections V.D.5 and V.D.6. 

Except for the absence of the assurance 

provisions, the remedy for 2012–2013 

would be the same as the State Budgets/ 

Limited Trading option, including 

compliance and penalty provisions 

described previously. 

The 2012–2013 transition period 

would provide time for sources to 

migrate to the new rule requirements in 

2014, such as preparing for the 

imposition of the assurance provisions 

and, for some states, tighter 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 costs, but would be required 

starting in 2014. EPA requests comment 

on the pros and cons of including 

assurance provisions or other 

limitations on trading during the 2012– 

2013 period. Section IV.F presents 

variability limits for the alternative 

where assurance provisions would 

apply during 2012 and 2013 (see Tables 

IV.F–1 through IV.F–4). 

d. Electric Reliability 

The State Budgets/Limited Trading 

remedy is not a risk to electric 

reliability. The option for sources to 

trade across state borders and to emit up 

to the specified state budget with 

variability limit gives ISOs 

(Independent System Operators) the 

flexibility to manage regional electricity 

generation so that reliability is 

maintained. For example, the operations 

of the electricity generation sector under 

the State Budgets/Limited Trading 

remedy, as compared to the option 

allowing only intrastate trading, would 

be less constrained by state borders and 

have greater flexibility to handle 

unexpected events such as extreme 

weather or the loss of generating 

capacity for extended periods of time. 

e. How Emissions Cap and Trade 

Programs Have Worked Under Title IV, 

the NOX SIP Call, and CAIR 

Even absent assurance provisions, cap 

and trade programs have resulted in 

broad-based emissions reductions 

distributed across the entire covered 

area, with the reductions coming where 

emissions were highest and most cost 

effective. The national 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. 

Æ An emissions cap is established 

and the programs are phased in, with 

increasing stringency to lower 

emissions. 

• Allowance allocation. 

Æ Authorizations to emit, i.e., 

allowances, are allocated to affected 

sources and are limited by each state’s 

trading budget. 

• Allowance trading. 

Æ Markets enable sources to trade 

allowances. 

• Flexible compliance. 

Æ Sources have the flexibility to 

choose the most efficient way to comply 

including adding emission control 

technologies, updating control 

technologies, optimizing existing 

controls, switching fuels, and buying 

allowances. 

• Annual reconciliation. 

Æ At the end of every compliance 

period, each source must surrender 

sufficient allowances to cover its 

emissions. Excess allowances may be 

sold or banked for future use. 

• Penalties and enforcement. 

Æ There are automatic penalties and 

potentially discretionary civil penalties 

for program noncompliance. 

• Stringent monitoring and reporting. 

Æ Sources must use approved 

monitoring methods under EPA’s 

stringent monitoring requirements (40 

CFR part 75) to monitor and report 

emissions. 

• Data transparency. 

Æ The data on key program elements, 

such as emissions, allocations, and 

allowance trades, are publicly available 

on EPA’s web site and in annual 

progress reports. 

About 50 government staff operate 

these cap and trade programs. They 

have been successful in achieving the 

emissions reductions goals at reasonable 

costs with virtually 100 percent program 

compliance. In the following 

paragraphs, specific results from the 

programs are described. These results 

are documented in program progress 

reports that are available on EPA’s Web 

site (http://www.epagov/airmarkets/ 

progress/progress-reports.html) and in 

the docket to this rule, as referenced at 

the end of each program section later. 

Title IV Acid Rain Program—Emissions 

Reductions 

Since program implementation in 

1995, the ARP has reduced 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 coalfired 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 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. 

See EPA’s docket for this rule and 

http://www.epagov/airmarkets/progress/ 

ARP_4.html. 


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88U.S. EPA, Our Nation’s Air Status and Trends 

through 2008, Office of Air Quality Planning and 

Standards, EPA–454/R–09–002, Research Triangle 

Park, NC, pp. 1, 17. 89 Ge ́go, E., P.S. Porter, A. Gilliland, and S.T. Rao, 

2007: Observation-Based Assessment of the Impact 

of Nitrogen Oxides Emissions Reductions on Ozone 

Air Quality over the Eastern United States. J. Appl. 

Meteor. Climatol., 46, 994–1008. 

90 Godowitch, J.M., Hogfrefe, C., & Rao, S.T. 2008. 

Diagnostic analyses of a regional air quality model: 

Changes in modeled processes affecting ozone and 

chemical-transport indicators from NOX point 

source emission reductions. Journal of Geophysical 

Research, 113, D19303, doi:10.1029/2007JD009537. 

91 Godowitch, J.M., Gilliland, A.B., Draxler, R.R., 

and Rao, S.T. 2008. Modeling assessment of point 

source NOX emission reductions on ozone air 

quality in the eastern United States. Atmospheric 

Environment, 42 (1), 87–100. 

92Ellerman, A. Denny. 2004. ‘‘The U.S. SO2 Capand-Trade Programme,’’ Tradeable Permits: Policy 

Evaluation, Design and Reform, chapter 3, pp. 71– 

97, OECD. 

93Schennach, 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. 

94Personal communication with Gary Hart, ICAPUnited, June 25, 2007 as quoted in Napolitano, S., 

J. Schreifels, G. Stevens, M. Witt, M. LaCount, R. 

Forte, & K. Smith. 2007. ‘‘The U.S. Acid Rain 

Program: Key Insights from the Design, Operation, 

and Assessment of a Cap-and-Trade Program.’’ 

Electricity Journal. Aug/Sept. 2007, Vol. 20, Issue 

7. doi:10.1016/j.tej.2007.07.001. 

95Tietenberg, T.H. 2006. Emissions Trading 

Principles and Practice. Washington, DC. Published 

by Resources for the Future. 

96 Ibid., p. 41. 

97 Ibid., p. 73. 

98 Ibid., pp. 70–71. 

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 emissions rate for 

the 10 highest electric demand days (as 

measured by megawatt hours of 

generation) consistently fell every year 

of the NBP. 

• The largest 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 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.88

Over the past several years a series of 

studies 89 90 91 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 

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 http:// 

www.epagov/airmarkets/progress/ 

NBP_4.html. 

CAIR—Emissions Reductions. 

Anticipation of the CAIR regional 

program in 2008 resulted in an 

additional 2.8 million tons of 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 allowance 

markets remained active. For a recent 

assessment on allowance markets, see 

http://www.epagov/airmarkets/

resource/docs/marketassessmnt.pdf. 

Transaction Costs. The cap and trade 

program results described previously 

are real, measurable, and very 

significant. These results demonstrate 

that cap and trade is a policy tool that 

can achieve cost-effective, broad 

reductions quickly to improve human 

health and the environment and help 

states meet their obligations to attain the 

NAAQS. While some have suggested 

that transaction costs associated with 

cap and trade programs were high or 

problematic, EPA has found no 

indication that this is the case. 

Transaction costs are important because 

they can diminish the incentive to trade 

or the amount traded. 

In fact, few empirical studies on 

transaction costs have been done. EPA 

has searched the literature and 

compiled a list of anecdotal discussions 

on transaction costs, including a study 

of the ARP’s SO2 cap and trade program 

by Ellerman 92 of MIT, published in 

2004. Ellerman suggests that, while no 

comprehensive study has been 

conducted on the subject, ‘‘* * * the 

creation of a standard unit of account in 

allowances and the lack of any review 

requirement for trading has avoided the 

very large transactions costs that limited 

* * * earlier experiments with 

emissions trading.’’ Other studies (see 

Schennach, 2000 93) suggest transaction 

costs are about one percent of the 

allowance price. An industry expert, 

Gary Hart,94 suggested that a typical fee 

charged by a brokerage firm is $0.50 for 

each SO2 allowance. 

Tietenberg, in his book, Emissions 

Trading Principles and Practice,95

explains the role of transaction costs 

and their impact on trading. Note that 

Tietenberg and many economists use 

the word, ‘‘permits,’’ in the same way 

EPA uses the word, ‘‘allowances.’’ 

Tietenberg defines transactions costs 

as ‘‘the costs, other than price, incurred 

in the process of exchanging goods and 

services. These include the costs of 

researching the market, finding buyers 

or sellers, negotiating and enforcing 

contracts for permit transfers, 

completing all the regulatory 

paperwork, and making and collecting 

payments.’’ 96 He also describes how to 

lower transaction costs, as follows: 

‘‘Transaction costs can be lowered by 

making permit transactions transparent, 

by the availability of exchanges and 

knowledgeable brokers, and by the 

sharing of information on the 

availability of cost-effective abatement 

technologies, while administrative costs 

can be lowered by continuous emissions 

monitoring and by software that 

streamlines monitoring and 

reporting.’’ 97 He goes on to say, ‘‘Price 

transparency (making prices public) can 

reduce the uncertainty associated with 

trading and facilitate negotiations about 

price and quantity. One good example is 

[the] public auctions held each spring 

for the Sulfur Allowance Program 

[ARP].’’ 98

Tietenberg contrasts EPA’s earlier 

credit-based trading programs in the 


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99Memo from ICF International to EPA Clean air 

Markets Division, September 17, 2008. Transaction 

Costs in Allowance Trading Markets. 

100 Ibid. 

101Note that in cases where EPA has not fully 

identified the quantity of emissions that represent 

significant contribution or interference with 

maintenance, state budgets define the emissions 

that remain after the part that has been identified 

is eliminated. 

1970s and 1980s (U.S. Emissions 

Trading Program (ETP)) with cap and 

trade programs, such as the Acid Rain 

Program for SO2. He says that while 

credit-based programs ‘‘typically 

involved a considerable amount of 

regulatory oversight at each step of the 

process (e.g., certification of credits and 

approval of each trade),’’ cap and trade 

programs use instead a system ‘‘that 

compares actual and authorized 

emissions at the end of the year, which 

can lower transactions costs’’ compared 

to a credit program. 

All the features Tietenberg highlights 

comprise fundamental aspects of EPA’s 

cap and trade program design. Program 

design remains one of the principle 

ways to ensure lower transaction costs. 

Over the last 15 years, EPA’s state-ofthe-art information management system 

has evolved in parallel with the 

advancement of technology in order to 

offer platforms for reporting and 

receiving data and for public access. 

EPA provides dedicated assistance for 

sources, states, and regions around the 

country on program operations and 

monitoring and reporting, specifically. 

With limited oversight of transactions, 

EPA focuses on recording data and 

information accurately, including 

allowance transfers, as well as ‘‘true-up’’, 

where actual emissions are reconciled 

with allowances held in accounts for 

compliance. 

These features of EPA’s program 

management lead to low transaction 

costs. EPA is attuned to trying to keep 

requirements as simple and 

straightforward as possible, and offers 

substantial and routine training to 

ensure successful program 

implementation and regulatory 

compliance. While some have equated 

the length of EPA’s trading program 

rules with higher transaction costs, in 

fact, the detailed regulatory sections, 

such as for allocations and the stringent 

monitoring requirements, form the basis 

of what actually allows the programs to 

function with limited oversight, 

virtually 100 percent compliance, 

public transparency, and nominal 

transaction costs. 

For the ARP, 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 

involved is in effect. See, e.g., 40 CFR 

96.155 (allowing banking). Further, 

allowances may be transferred from one 

account to another with no restrictions 

except the requirements that the 

authorized account representative of the 

transferor account submit to EPA a 

simple (generally electronic) allowance 

transfer form identifying the allowances 

to be transferred and the account to 

receive them, and that the allowances 

must be currently recorded in the 

transferor account. See, e.g., 40 CFR 

96.160 (requiring submission of 

specified allowance transfer form) and 

96.161(a)(2) (requiring that allowance be 

in transferor account). This 

transparency of data and availability of 

information allows the allowance 

market to function smoothly. 

EPA research found no indications 

that transaction costs have been a 

problem. From discussions with a 

leading industry consultant we learned 

that there is enough competition among 

the approximately fifteen brokerage 

houses that any attempt at charging fees 

in excess of market standards will be 

bid down through competition.99 In 

many instances, clients can negotiate 

fees even lower than market averages. 

Financial exchanges, such as the 

Chicago Climate Exchange and New 

York Mercantile Exchange, added 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.100 These transaction costs 

are low and not expected to affect 

program outcome. 

In summary, EPA believes its cap and 

trade programs functioned efficiently 

and did not result in high transaction 

costs for several reasons. First, in 

developing the regulations for the 

trading programs, EPA strove to make 

the programs as transparent as possible 

in order to ensure that relevant data 

were available to the market, to 

minimize regulatory oversight of trading 

activity, and to let the market work 

unhampered. Strong markets exist that 

have seen upwards of 273 million 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 concern about the costs of 

making allowance transfers. For 

example, EPA has received no comment 

in the rulemaking proceedings for the 

trading programs raising concern about 

the level of transactions costs for 

allowance transfers under these 

programs, and no party challenged the 

allowance transfer provisions on appeal 

of any of the trading program rules. 

In addition, all available information 

indicates that actual transactions costs 

are very low. For a list of some articles 

written by scholars and economists over 

the past 15 years on transaction costs, 

see the docket for this rule. 

f. How the Remedy in the Proposed FIPs 

Is Consistent With the Court’s Opinions 

The proposed remedy discussed in 

this section effectuates the statutory goal 

of prohibiting sources within the state 

from contributing to nonattainment or 

interfering with maintenance in any 

other state. See North Carolina, 531 F.3d 

at 908. The proposed FIPs eliminate all 

or the emissions that EPA has identified 

as significantly contributing to 

downwind nonattainment or 

interference with maintenance in 

today’s proposed action by requiring 

sources to participate in emissions 

trading programs that allow intrastate 

trading and limited interstate trading, 

and that also include provisions to 

ensure that no state’s emissions exceed 

that state’s budget with variability limit. 

These assurance provisions, combined 

with the requirement that all sources 

hold emissions allowances sufficient to 

cover their emissions, effectuate the 

requirement that emissions reductions 

occur ‘‘within the State.’’ 

A state’s ‘‘significant contribution’’ is 

the portion of emissions that must be 

eliminated.101 State budgets represent 

EPA’s estimate of the remaining 

emissions after elimination of 

significant contribution, but in actuality 


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the amount of remaining emissions may 

vary. As explained in greater detail 

previously, both the budgets and the 

assurance provisions recognize the 

inherent variability in state EGU 

emissions. EPA recognizes that shifts in 

generation due to, among other things, 

changing weather patterns, demand 

growth, or disruptions in electricity 

supply from other units can affect the 

amount of generation needed in a 

specific state and thus baseline EGU 

emissions from that state. Because 

states’ baseline emissions are variable, 

their remaining emissions after all 

significant contribution is eliminated 

are also variable. In other words, EGU 

emissions in a state, whose sources have 

installed all controls and taken all 

measures necessary to eliminate its 

significant contribution, could in fact 

exceed the state budget without 

variability. For this reason, the 

assurance provisions limit a state’s 

emissions to the state’s budget with 

variability limit. 

In addition, the requirement that all 

sources hold emissions allowances (and 

the fact that the total number of 

emissions allowances allocated will be 

equal to the sum of all state budgets 

without variability) ensures that the use 

of variability limits both takes into 

account the inherent variability of 

baseline EGU emissions in individual 

states (i.e., the variability of total state 

EGU emissions before the elimination of 

significant contribution) and recognizes 

that this variability is not as great in a 

larger region. 

The variability of emissions across a 

larger region is not as large as the 

variability of emissions in a single state 

for several reasons. Increased EGU 

emissions in one state in one control 

period often are offset by reduced EGU 

emissions in another state within the 

control region in the same control 

period. In a larger region that includes 

multiple states, factors that affect 

electricity generation, and thus EGU 

emissions levels, are more likely to vary 

significantly within the region so that 

resulting emissions changes in different 

parts of the region are more likely to 

offset each other. For example, a broad 

region can encompass states with 

differing weather patterns, with the 

result that increased electricity demand 

and emissions due to weather in one 

state may be offset by decreased demand 

and emissions due to weather in another 

state. By further example, a broad region 

can encompass states with differing 

types of industrial and commercial 

electricity end-users, with the result that 

changes in electricity demand and 

emissions among the states due to the 

effect of economic changes on industrial 

and commercial companies may be 

offsetting. Similarly, because states in a 

broad region may vary in their degree of 

dependence on fossil-fuel-based electric 

generation, the impact of an outage of 

non-fossil-fuel-based generation (e.g., a 

nuclear plant) in one state may have a 

very different impact in that state than 

on other states in the region. Thus, EPA 

does not believe it is necessary to allow 

total regional allowance allocations for 

the states covered by a given trading 

program to exceed the sum of all state 

budgets without variability for these 

states. 

For these reasons, the fact that the 

proposed use of state budgets with the 

variability limit may allow limited 

shifting of emissions between states is 

not inconsistent with the Court’s 

holding that emissions reductions must 

occur ‘‘within the state.’’ North Carolina, 

531 F.3d at 907. Under the proposed 

FIPs, no state may emit more than its 

budget with variability limit and total 

emissions cannot exceed the sum of all 

state budgets without variability. This 

approach takes into account the 

inherent variability of the baseline 

emissions without excusing any state 

from eliminating its significant 

contribution. It is thus consistent with 

the statutory mandate of section 

110(a)(2)(D)(i)(I) as interpreted by the 

Court. 

g. Why EPA Is Proposing the State 

Budgets/Limited Trading Option 

The FIPs that EPA is proposing use 

the State Budgets/Limited Trading 

remedy to eliminate all of the significant 

contribution and interference with 

maintenance that EPA has identified. 

This remedy—which would use state 

budgets (see section IV) and allow full 

trading within each state and limited 

trading outside of each state—would be 

a cost-effective method for eliminating 

all or part of each state’s emissions that 

constitute a significant contribution and 

interfere with maintenance, would be 

consistent with the Court’s decision in 

North Carolina v. EPA, and would 

address the issues raised by the Court. 

In the first phase (2012 and 2013), the 

proposed remedy would provide a new 

interstate trading program that would 

ensure existing and planned pollution 

controls operate. Units would be 

required to run their existing, or already 

planned, pollution control devices 

when the units are operating. The State 

Budgets/Limited Trading remedy would 

use the new state budgets described in 

section IV and allocate allowances to 

individual sources using a methodology 

directly related to the methodology used 

to identify emissions that significantly 

contribute to nonattainment or interfere 

with maintenance in downwind areas. 

EPA believes that because the location 

of existing and already planned 

pollution controls for 2012 and 2013 is 

known, the use of these budgets, even 

without the added assurance provisions, 

would assure that the necessary 

emissions reductions would occur in 

each state under the trading programs 

during those years. The impact of the 

resulting emissions reductions on 

atmospheric concentrations of 

particulate matter and other pollution, 

and subsequent benefits for the 

environment and human health, would 

be significant and are described in 

sections III.B and IX. The proposed 

remedy would offer the most 

expeditious approach practicable for 

compliance in 2012–2013, given the 

short time available for sources, states, 

and EPA to implement a transition from 

CAIR. While there is some uncertainty 

about how quickly units potentially 

capable of switching fuels would 

actually be able to implement such fuel 

switching, the banking provisions of the 

State Budgets/Limited Trading approach 

would provide incentives to reduce 

emissions as quickly and early as 

possible. The trading provisions would 

provide flexibility for sources to 

purchase allowances in the meantime, 

without the risks of unexpected high 

costs, non-compliance, or the inability 

to operate if unable to switch fuels. The 

remedy would be relatively easy for 

sources and states to understand and 

follow as they transition from prior 

trading programs to a new regime, 

beginning in 2014, that would include 

limits on interstate trading. 

The second phase would begin in 

2014 with tighter state-specific 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 compromised and states 

can depend on emissions reductions in 

meeting local air quality goals. 

The limited interstate trading 

permitted in this proposed remedy 

would address some of the problematic 

issues identified in the alternative 

options discussed later, such as, under 

the intrastate trading option, concerns 

about the administrative burden and 

needed resources associated with 

administering 82 new trading programs 

(with 82 new sets of allowances), 


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conducting 82 annual auctions, 

concentrated allowance market power 

within individual states, and regional 

electricity reliability. In particular, the 

interstate trading component with 

assurance provisions would mean that 

allowances issued for one state for a 

trading program could be used in any of 

the states included in the respective 

trading program. This feature of the 

proposed remedy would create a 

regionwide allowance market, rather 

than single-state allowance markets 

where individual owners of sources 

would be much more likely to have 

market power (see discussion later in 

section V.D.5). Further, the interstate 

trading component with assurance 

provisions would provide source 

owners with much more flexibility to 

ensure electric reliability in the event of 

future variability in electricity demand 

(e.g., due to weather or economic 

changes) or in the availability of specific 

individual electricity generation 

facilities. 

In addition, the proposed State 

Budgets/Limited Trading remedy 

provides reductions at a lower cost than 

the direct control option described later 

and is flexible enough to accommodate 

unit-specific circumstances. In contrast, 

the direct control option described later 

would involve a complex process of 

determining unit-by-unit emissions 

limits that might need to take account 

of unit-specific circumstances. 

Moreover, this option would be roughly 

$600 million (2006$) more expensive 

than the proposed remedy in 2012. See 

section V.E for more details on projected 

costs and emissions. 

In summary, EPA believes that 

interstate trading, although limited by 

the assurance provisions, would allow 

source owners to choose among several 

compliance options to achieve required 

emissions reductions in the most costeffective manner, such as installing 

controls, changing fuels, reducing 

utilization, buying allowances, or any 

combination of these actions. Interstate 

trading with assurance provisions 

would also allow the electricity sector to 

continue to operate as an integrated, 

interstate system able to provide electric 

reliability. Compared to the alternative 

options, EPA believes the State Budgets/ 

Limited Trading remedy would provide 

the greatest flexibility to companies 

complying with the rules and is the 

approach most likely to achieve the 

goals and principles outlined in section 

III.C. 

The proposed remedy provides 

intrastate and interstate trading 

components that simplify 

implementation for EPA (and, where 

applicable, states) and sources and 

results in cost-effective achievement of 

required emissions reductions. Resource 

needs for EPA and sources to implement 

the proposed remedy are expected to be 

comparable to the resources necessary 

to implement CAIR. 

EPA believes the State Budgets/ 

Limited Trading proposed remedy 

provides more assurance that the 

emissions levels necessary to address 

NAAQS nonattainment are not 

exceeded than most previous regulatory 

programs such as rate-based direct 

control programs and even 

nonattainment plans, none of which 

places an absolute cap on emissions. 

EPA has pointed out, in contrast, that 

the results from cap and trade programs 

such as the Acid Rain and 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 added 

assurance that emissions reductions 

now will occur on a state-by-state basis, 

not just overall at a regional level. These 

assurance provisions would prohibit 

states from exceeding their state-level 

budgets with variability limits and 

impose stringent and costly allowance 

surrender requirements that are known 

upfront to deter exceedances. EPA is 

confident that the proposed program is 

both reasonable to implement and 

stronger than the alternative options. 

Additionally, this remedy approach 

and the method EPA proposes for 

determining significant contribution 

together provide a workable regulatory 

structure for not only dealing with the 

transport problem for the existing 

NAAQS, but also would be usable in the 

years ahead when EPA considers further 

revisions of the NAAQS, notably for 

ozone and fine particles. EPA requests 

comment on the State Budgets/Limited 

Trading proposed remedy. EPA is also 

requesting comment on the two options 

described later in sections V.D.5 and 

V.D.6. 

h. Other Limited Interstate Trading 

Options Evaluated 

EPA considered a range of ways to 

create an interstate-trading-withlimitations option consistent with the 

direction provided by the Court. One 

option considered was to put in place 

simultaneously intrastate trading with 

direct control requirements and 

interstate trading with direct control 

requirements. The challenges associated 

with developing direct control 

requirements are discussed in section 

V.D.6 later. 

EPA also considered interstate trading 

with backstop provisions, which were 

rejected as not workable. EPA 

considered a backstop provision that 

prohibited the units in a state from 

future participation in the interstate 

trading program if the state’s emissions 

in a control period in any year exceeded 

the state’s budget with variability. In 

that event, the units would be limited to 

intrastate trading only in the control 

period of the next year. This is not 

EPA’s proposed option because data on 

annual emissions are not final until 

several months into the next year, 

making it hard for the units in a state 

to know early enough whether they 

would be in the interstate trading 

program or an intrastate trading program 

for that next year. This would make 

compliance planning and 

implementation of compliance plans 

extremely difficult and adversely affect 

allowance markets. 

In summary, EPA rejected these 

alternatives as more complicated and 

perhaps problematic to implement. 

Instead, EPA is proposing the State 

Budgets/Limited Trading remedy, 

which is similar in many ways to the 

approaches implemented in the past 

that have succeeded in reducing 

emissions. However, in order to address 

the Court’s concerns about trading, the 

proposed remedy includes assurance 

provisions to ensure that the remedy 

removes each upwind state’s significant 

contribution and interference with 

maintenance. The ‘‘Other Remedy 

Options Evaluated’’ TSD in the docket 

contains greater detail on the 

deliberations undertaken to evaluate 

other options for this rulemaking. 

i. Structure and Key Elements of 

Proposed Transport Rule Trading 

Program Rules for State Budgets/ 

Limited Trading 

This preamble section describes the 

structure and key elements of the 

proposed Transport Rule trading 

program rules for the State Budgets/ 

Limited Trading remedy in the 

proposed FIPs. Proposed regulatory text 

that would be added to the Code of 

Federal Regulations if this option is 

finalized appears at the end of this 

notice. EPA requests comment on the 

structure and key elements of the 

program as well as on the proposed 

regulatory text. 

In order to make the proposed FIP 

trading program rules as simple and 

consistent as possible, EPA designed 

them so that the proposed rules for each 

of the trading programs (i.e., the 

Transport Rule NOX Annual trading 

program, Transport Rule NOX Ozone 

Season trading program, Transport Rule 


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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 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 sources, 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. Some definitions would be similar to 

those used in prior EPA-administered 

trading programs but with some 

substantive differences. For example, 

the definitions of ‘‘cogeneration unit’’ 

and ‘‘fossil-fuel-fired,’’ used in the 

applicability provisions and discussed 

in this section of the preamble, would 

be similar to those in prior trading 

programs but with changes to minimize 

the need for data concerning individual 

units or combustion devices for periods 

before 1990. 

A few new definitions would be 

included to reflect unique provisions of 

the proposed Transport Rule trading 

programs. For example, the terms, 

‘‘owner’s assurance level’’ and ‘‘owner’s 

share’’, would be used in the Transport 

Rule assurance provisions and defined 

in the proposed Transport Rule trading 

program rules. The assurance provisions 

are discussed previously in section 

V.D.4.b. 

(ii) §§ 97.404 and 97.405, 97.504 and 

97.505, 97.604 and 97.605, and 97.704 

and 97.705—Applicability and Retired 

Units 

The applicability provisions would be 

the same for each of the proposed 

Transport Rule trading programs, except 

that the provisions would reflect 

(through the definition of ‘‘state’’) 

differences in the specific states whose 

EGUs are covered by the respective 

Transport Rule trading programs (as 

discussed in section IV.D of this 

preamble). In general, the proposed 

Transport Rule trading programs would 

cover fossil fuel-fired boilers and 

combustion turbines serving an 

electrical generator with a nameplate 

capacity exceeding 25 MWe and 

producing power for sale, with the 

exception of certain cogeneration units 

and solid waste incineration units. The 

applicability provisions are discussed 

previously in section V.D.4.b. The provisions exempting 

permanently retired units from most of 

the requirements of the Transport Rule 

trading programs would be the same for 

each of the trading programs. The 

purpose of the retired units’’ exemption 

would be to avoid requiring units that 

are permanently retired to continue to 

operate and maintain emission 

monitoring systems, to report quarterly 

emissions, and to hold allowances, as of 

the allowance transfer deadline, 

sufficient to cover their emissions 

determined in accordance with the 

monitoring and reporting requirements. 

Consequently, the retired unit 

provisions would exempt these units 

from the rule sections imposing the 

relevant monitoring, recordkeeping, and 

reporting requirements and allowanceholding requirements. However, an 

owner would include each of these 

permanently retired units that it owns 

in determining whether and, if so, how 

many allowances the owner would be 

required to surrender in compliance 

with the assurance provisions. As 

discussed earlier in this section, while 

these units would have zero emissions 

once they are permanently retired, the 

units could continue to receive 

allowance allocations for several years 

thereafter. Consequently, an owner 

would include these units in 

determining whether the owner’s share 

of total emissions of covered units in a 

state exceeded its share (generally based 

on the allowances allocated to its units) 

of the state budget with the variability 

limit and thus whether the owner would 

have to surrender allowances under the 

assurance provisions. 

The exemption for a retired unit 

would begin on the day the unit is 

permanently retired. The unit’s 

designated representative (i.e., the 

person authorized by the owners and 

operators to make submissions and 

handle other matters) would be required 

to submit notification to the 

Administrator within 30 days of the 

unit’s permanent retirement. 

The retired unit exemption provisions 

would not directly address any permitrelated matters concerning these units. 

This would be consistent with the 

general approach under the Transport 

Rule trading program rules of leaving 

permitting matters largely to be 

addressed by the existing, applicable 

state and federal title V permit 

programs. Permitting is discussed in 

section VIII of this preamble. 

(iii) §§ 97.406, 97.506, 97.606, and 

97.706—Standard Requirements 

The basic requirements applicable to 

owners and operators of units and 

sources covered by the proposed 

Transport Rule trading programs and 

presented as standard requirements 

would include: Designated 

representative requirements; emissions 

monitoring, reporting, and 

recordkeeping requirements; emissions 

requirements comprising emissions 

limitations and assurance provisions; 

permit requirements; additional 

recordkeeping and reporting 

requirements; liability provisions; and 

provisions describing the effect of the 

Transport Rule trading program 

requirements on other Act provisions. 

The paragraphs, in the standard 

requirements section, that would 

address designated representative 

requirements and emissions monitoring, 

reporting, and recordkeeping 


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requirements would reference the 

details of these requirements in other 

sections of the proposed Transport Rule 

trading program rules. 

The paragraphs addressing emissions 

requirements would describe these 

requirements in detail and reference 

other sections that would set forth the 

procedures for determining compliance 

with the emissions limitations and 

assurance provisions. These paragraphs 

would also explain that: Transport Rule 

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 CAA; 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 

limited to stating that no title V permit 

revisions would be necessary to account 

for allowance allocation, holding, 

deduction, or transfer and that the 

minor permit modification procedures 

could be used to add or change general 

descriptions in the title V permits of the 

monitoring and reporting approach used 

by the units covered by each title V 

permit. The paragraphs on 

recordkeeping and reporting would 

generally require owners and operators 

to keep on site for 5 years copies (which 

could be electronic) of certificates of 

representation, emissions monitoring 

information (including quarterly 

emissions data), and submissions and 

records demonstrating compliance with 

the proposed Transport Rule trading 

programs. The paragraphs on liability 

would state that each covered source 

and covered unit would be required to 

meet the Transport Rule trading 

program requirements, any provision 

applicable to a source or designated 

representative would be applicable to 

the source and unit owners and 

operators, and any provision applicable 

to a unit or designated representative 

would be applicable to the unit owners 

and operators. The paragraph on the 

effect on other CAA provisions would 

state that the Transport Rule trading 

programs do not exempt or exclude 

owners and operators from any other 

requirements under the CAA, an 

approved SIP, or a federally enforceable 

permit. 

(iv) §§ 96.407, 97.507, 97.607, and 

97.707—Computation of Time 

These sections would clarify how to 

determine the deadlines referenced in 

the proposed Transport Rule trading 

program rules. For example, deadlines 

falling on a weekend or holiday are 

extended to the next business day. 

These are the same computation-of-time 

provisions used in prior EPAadministered trading programs. 

(v) §§ 97.408, 97.508, 97.608, 97.708 and 

Part 78—Administrative Appeal 

Procedures 

Final decisions of the Administrator 

under the proposed Transport Rule 

trading program rules would be 

appealable to EPA’s Environmental 

Appeals Board under the regulations 

that are set forth in part 78 (40 CFR part 

78) and are proposed to be revised to 

accommodate such appeals. 

Specifically, the list in § 78.1 of the 

types of final decisions that could be 

appealed under Part 78 would be 

expanded to include specific types of 

decisions under the proposed Transport 

Rule trading program rules. 

Further, under the approach in the 

existing part 78, an ‘‘interested person’’ 

(in addition to the official representative 

of owners and operators or an allowance 

account involved in a matter) may 

petition for an administrative appeal of 

a final decision of the Administrator. In 

order to expand the ‘‘interested person’’ 

definition (which is currently in part 72 

of the ARP regulations) and make the 

definition more readily accessible to 

readers of part 78, the definition would 

be removed from § 72.2, added in § 78.2, 

and expanded in a way that would 

cover the proposed trading program 

rules. Provisions concerning public 

availability of information, and 

provisions concerning computation of 

time (revised to be consistent with the 

requirements for computation of time 

used by the Environmental Appeals 

Board in other types of administrative 

proceedings), would also be moved to 

§ 78.2. In particular, the revised 

‘‘interested person’’ definition would 

include, with regard to a decision 

appealable under Part 78, any person 

who—in connection with the 

Administrator’s process of making that 

decision—submitted comments, 

testified at a public hearing, submitted 

objections, or submitted their name to 

be included by the Administrator in an 

interested persons list. 

In addition, § 78.3 would be revised to 

allow for petitions for administrative 

appeal of decisions of the Administrator 

under the proposed Transport Rule 

trading programs. Further, § 78.4 would 

be expanded to state that filings on 

behalf of owners and operators of a 

covered source or unit under the 

proposed Transport Rule trading 

programs would have to be signed by 

the designated representative of the 

source or unit. Filings on behalf of 

persons with an interest in allowances 

in an account in the proposed programs 

would have to be signed by the 

authorized account representative of the 

account. 

(2) Allowance Allocations 

Sections 97.410 through 97.412, 

97.510 through 97.512, 97.610 through 

97.612, and 97.710 through 97.712 

would set forth: Certain information 

related to allowance allocation and for 

implementation of the assurance 

provisions; the timing for allocation of 

allowances to existing and new units; 

and the procedures for new unit 

allocations. In particular, these sections 

would include tables providing, for each 

state covered by the particular proposed 

Transport Rule trading program and for 

each year, the state trading budget 

(without the variability limit), new unit 

set-aside, and one-year and three-year 

variability limits. With regard to 

existing units, these sections would also 

state that existing units would be 

allocated the allowances set forth in 

appendix A of the relevant Transport 

Rule trading program rules. These 

allocations would be permanent (taking 

into account the reductions in 

allocations, for the Transport Rule SO2

Group 1 trading program, from Phase I 

to Phase II) with one exception. A unit 

that does not operate (i.e., has no heat 

input) for three consecutive years 

starting in 2012 would continue to 

receive its Appendix A allocation for 

those years plus only three more years. 

Starting in the seventh year, the 

Administrator would stop recording the 

allocations for the unit and would 

instead add to the new unit set-aside the 

allowances that would otherwise have 

been recorded for the non-operating 

unit. Because the proposed unit-by-unit 

allocations are set forth in the ‘‘State 

Budgets, Unit Allocations, and Unit 

Emissions Rates’’ TSD cited previously, 


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the proposed Transport Rule trading 

program rules do not repeat these 

allocations in Appendix A to each rule. 

Instead, each Appendix A is reserved, 

and EPA proposes to include the unitby-unit allocations, for each Transport 

Rule trading program, in Appendix A to 

the respective final Transport Rule 

trading program rules. 

With regard to new units (as well as 

units whose allocations are subject to 

the requirement that the Administrator 

not record them or that the 

Administrator deduct the amount of the 

allocation and units that lost their 

allocations after not operating and that 

subsequently began operating again), the 

owner and operator of such units could 

request, by a specified deadline each 

year, an allocation from the new unit 

set-aside for that year and each year 

thereafter. The allocation would equal 

that unit’s emissions—as determined in 

accordance with part 75 (40 CFR part 

75)—for the control period (annual or 

ozone season, depending on the 

Transport Rule trading program 

involved) in the preceding year. The 

Administrator would determine 

whether the total number of properly 

requested allowance allocations for all 

units in a state for a control period 

would exceed the amount in the new 

unit set-aside for the state for the control 

period. If not, the Administrator would 

allocate consistent with all proper 

requests. If the total number would 

exceed the new unit set-aside, the 

Administrator would allocate to each 

properly requesting unit its 

proportionate share of the new unit setaside. The Administrator would provide 

notice of these determinations (which 

would reflect these calculations rather 

than any exercise of discretion on the 

part of the Administrator) through 

issuance of a notice of data availability 

to which parties could submit 

objections and a second notice 

addressing any objections. Any 

unallocated allowances in the new unit 

set-aside would be allocated to existing 

units in proportion to their current 

allocations. 

If a unit that was not really a covered 

unit or a unit that was not subject to the 

allowance-holding requirement were 

allocated allowances, the proposed 

provisions set forth a process under 

which the allocation would not be 

recorded or the amount of the recorded 

allocation would be deducted, with one 

exception. The exception would be if 

the process of determining compliance 

with the emission limitation for the 

source that includes the unit were 

already completed, in which case no 

action would be taken to account for the 

erroneous allocation for the control 

period involved. 

(3) Designated Representatives and 

Alternate Designated Representatives 

Sections 97.413 through 97.418, 

97.513 through 97.518, 97.613 through 

97.618, and 97.713 through 97.718 

would establish the procedures for 

certifying and authorizing the 

designated representative, and alternate 

designated representative, of the owners 

and operators of a source and the units 

at the source and for changing the 

designated representative and alternate 

designated representative. These 

sections would also describe the 

designated representative’s and 

alternate designated representative’s 

responsibilities and the process through 

which he or she could delegate to an 

agent the authority to make electronic 

submissions to the Administrator. These 

provisions would be patterned after the 

provisions concerning designated 

representatives and alternates in prior 

EPA-administered trading programs. 

The designated representative would 

be the individual authorized to 

represent the owners and operators of 

each covered source and covered unit at 

the source in matters pertaining to all 

Transport Rule trading programs to 

which the source and units were 

subject. This approach would ensure 

that one individual was required to be 

knowledgeable about the requirements 

of, and responsible for compliance with, 

all Transport Rule trading programs. 

One alternate designated representative 

could be selected to act on behalf of, 

and legally bind, the designated 

representative and thus the owners and 

operators. Because the actions of the 

designated representative and alternate 

would legally bind the owners and 

operators, the designated representative 

and alternate would have to submit a 

certificate of representation certifying 

that each was selected by an agreement 

binding on all such owners and 

operators and was authorized to act on 

their behalf. 

The designated representative and 

alternate would be authorized upon 

receipt by the Administrator of the 

certificate of representation. This 

document, in a format prescribed by the 

Administrator, would include: Specified 

identifying information for the covered 

source and covered units at the source 

and for the designated representative 

and alternate; the name of every owner 

and operator of the source and units; 

and certification language and 

signatures of the designated 

representative and alternate. All 

submissions (e.g., monitoring plans, 

monitoring system certifications, and 

allowance transfers) for a covered 

source or covered unit would have to be 

submitted, signed, and certified by the 

designated representative or alternate. 

Further, upon receipt of a complete 

certificate of representation, the 

Administrator would establish a 

compliance account in the Allowance 

Management System for the source 

involved. 

In order to change the designated 

representative or alternate, a new 

certificate of representation would have 

to be received by the Administrator. A 

new certificate of representation would 

also have to be submitted to reflect 

changes in the owners and operators of 

the source and units involved. However, 

new owners and operators would be 

bound by the existing certificate of 

representation even in the absence of 

such a submission. 

In addition to the flexibility provided 

by allowing an alternate to act for the 

designated representative (e.g., in 

circumstances where the designated 

representative might be unavailable), 

additional flexibility would be provided 

by allowing the designated 

representative or alternate to delegate 

authority to make electronic 

submissions on his or her behalf. The 

designated representative or alternate 

could designate agents to submit 

electronically certain specified 

documents. The previously-described 

requirements for designated 

representatives and alternates would 

provide regulated entities with 

flexibility in assigning responsibilities 

under the Transport Rule trading 

programs, while ensuring accountability 

by owners and operators and 

simplifying the administration of the 

proposed Transport Rule trading 

programs. 

(4) Allowance Management System 

The Transport Rule trading program 

rules listed later would establish the 

procedures and requirements for using 

and operating the Allowance 

Management System (which is the 

electronic data system through which 

the Administrator would handle 

allowance allocation, holding, transfer, 

and deduction), and for determining 

compliance with the emissions 

limitations and assurance provisions, in 

an efficient and transparent manner. 

The Allowance Management System 

would also provide the allowance 

markets with a record of ownership of 

allowances, dates of allowance transfers, 

buyer and seller information, and the 

serial numbers of allowances 

transferred. Consistent with the 

approach in prior EPA-administered 

trading program, allowance price 


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information would not be included in 

the Allowance Management System. 

EPA’s experience is that private parties 

(e.g., brokers) are in a better position to 

obtain and disseminate timely, accurate 

allowance price information than is 

EPA. For example, because not all 

allowance transfers are immediately 

reported to the Administrator for 

recordation, the Administrator would 

not be able to ensure that any reported 

price information associated with the 

transfers would reflect current market 

prices. 

(vi) §§ 97.420, 97.520, 97.620, and 

97.720—Compliance and General 

Accounts 

The Allowance Management System 

would contain two types of accounts: 

compliance accounts, one of which the 

Administrator would establish for each 

covered source upon receipt of the 

certificate of representation for the 

source; and general accounts, which 

could be established by any entity upon 

receipt by the Administrator of an 

application for a general account. A 

compliance account would be the 

account in which any allowances used 

by the covered source for compliance 

with the emissions limitations and 

assurance provisions would have to be 

held. The designated representative and 

alternate for the source would also be 

the authorized account representative 

and alternate for the compliance 

account. Using source-level, rather than 

unit-level accounts, would provide 

owners and operators more flexibility in 

managing their allowances for 

compliance, without jeopardizing the 

environmental goals of the Transport 

Rule trading programs, because the 

source-level approach would avoid 

situations where a unit would hold 

insufficient allowances and would be in 

violation of allowance-holding 

requirements even though units at the 

same source had more than enough 

allowances to meet these requirements 

for the entire source. 

General accounts could be used by 

any person or group for holding or 

trading allowances. However, 

allowances could not be used for 

compliance with emissions limitations 

or assurance provisions so long as the 

allowances were held in, and not 

properly and timely transferred out of, 

a general account. To open a general 

account, a person or group would have 

to submit an application for a general 

account, which would be similar in 

many ways to a certificate of 

representation. The application would 

include, in a format prescribed by the 

Administrator: The name and 

identifying information of the 

individual who would be the authorized 

account representative and of any 

individual who would be the alternate 

authorized account representative; an 

identifying name for the account; the 

names of all persons with an ownership 

interest with the respect to allowances 

held in the account; and certification 

language and signatures of the 

authorized account representative and 

alternate. The authorized account 

representative and alternate would be 

authorized upon receipt of the 

application by the Administrator. The 

provisions for changing the authorized 

account representative and alternate, for 

changing the application to take account 

of changes in the persons having an 

ownership interest with respect to 

allowances, and for delegating authority 

to make electronic submissions would 

be analogous to those applicable to 

comparable matters for designated 

representatives and alternates. 

(vii) §§ 97.421 Through 97.423, 97.521 

Through 97.523, 97.621 Through 

97.623, and 97.721 Through 97.723— 

Recordation of Allowance Allocations 

and Transfers 

By September 1, 2011, the 

Administrator would record allowance 

allocations for existing units, based on 

Appendix A to each proposed Transport 

Rule trading program rule, for 2012 

through 2014. By June 1, 2012 and June 

1 of each year thereafter, the 

Administrator would record such 

allowance allocations for each proposed 

Transport Rule trading program for the 

third year after the year of the 

recordation deadline, e.g., for 2015 in 

2012. Recording these allowance 

allocations about 3 years in advance of 

the first year for which they could be 

used for compliance would facilitate 

compliance planning by owners and 

operators and promote robust allowance 

markets, including futures markets for 

allowances. By September 1 (for the 

Transport Rule 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 set-aside. Because this 

would occur before the allowance 

transfer deadline for each proposed 

Transport Rule trading program 

involved, this would still allow for 

trading and thereby promote robust 

allowance markets. 

The process for transferring 

allowances from one account to another 

would be quite simple. A transfer would 

be submitted providing, in a format 

prescribed by the Administrator, the 

account numbers of the accounts 

involved, the serial numbers of the 

allowances involved, and the name and 

signature of the transferring authorized 

account representative or alternate. If 

the transfer form containing all the 

required information were submitted to 

the Administrator and, when the 

Administrator attempted to record the 

transfer, the transferor account included 

the allowances identified in the form, 

the Administrator would record the 

transfer by moving the allowances from 

the transferor account to the transferee 

account within 5 business days of the 

receipt of the transfer form. 

(viii) §§ 97.424, 97.524, 97.624, and 

97.724—Compliance With Emissions 

Limitations 

Once a control period has ended (i.e., 

December 31 for the Transport Rule 

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 

source’s total emissions for the control 

period. The authorized account 

representative could identify specific 

allowances to be deducted, but, in the 

absence of such identification or in the 

case of a partial identification, the 

Administrator would deduct on a firstin, first-out basis. 

If a source were to fail to hold 

sufficient allowances for compliance, 

then the owners and operators would 

have to provide, for deduction by the 

Administrator, 2 allowances allocated 

for the control period in the next year 

for every allowance that the owners and 

operators failed to hold as required to 

cover emissions. In addition, the owners 

and operators would be subject to 

discretionary civil penalties for each 

violation, with each ton of unauthorized 

emissions and each day of the control 


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period involved constituting a violation 

of the Clean Air Act. 

EPA believes that it is important to 

include a requirement for an automatic 

deduction of allowances. The deduction 

of one allowance per allowance that the 

owners and operators failed to hold 

would offset this failure. The deduction 

of another allowance per allowance that 

the owners and operators failed to hold 

would provide an automatic penalty 

that could not be avoided, regardless of 

any explanation provided by the owners 

and operators for their failure, and 

would therefore provide a strong 

incentive for compliance with the 

allowance-holding requirement by 

ensuring that non-compliance would be 

a significantly more expensive option 

than compliance. 

(ix) §§ 97.425, 97.525, 97.625, and 

97.725—Compliance With Assurance 

Provisions 

EPA proposes to include assurance 

provisions in the Transport Rule trading 

programs in order to ensure that each 

state would eliminate that part of its 

significant contribution and interference 

with maintenance that EPA has 

identified in today’s proposed action 

(see section V.D.4.b previously). As 

previously discussed, a requirement that 

owners surrender allowances under the 

assurance provisions would be triggered 

only for owners of units in a state where 

the total state EGU emissions for a 

control period would exceed the 

applicable state budget with the 

variability limit. Moreover, only an 

owner whose units’ emissions would 

exceed the owner’s share of the state 

budget with the variability limit would 

be subject to the allowance surrender. 

The process of determining, for a 

given control period, which states 

would have total EGU emissions 

sufficient to trigger the allowance 

surrender requirement, which owners 

would be subject to the allowance 

surrender, and whether those owners 

were in compliance would be 

implemented in a series of steps. (The 

dates summarized later apply to the 

proposed annual programs; the dates for 

the proposed ozone season program 

would be earlier.) 

First, the Administrator would 

perform the calculations necessary to 

determine whether any states had total 

state EGU emissions for a control period 

greater than the state budget with the 

variability limit, applying both the 

1-year and the 3-year variability limits 

discussed earlier. By June 1 (starting in 

2015), the Administrator would 

promulgate a notice of availability of the 

results of these calculations and provide 

an opportunity for submission of 

objections. By August 1, the 

Administrator would promulgate a 

second notice of availability of any 

necessary adjustments to the 

calculations and the reasons for 

accepting or rejecting any properly 

submitted objections. 

Second, by August 15, the designated 

representative of every Transport Rule 

source in a state identified in the August 

1 notice as having control period 

emissions in excess of the budget with 

the variability limit would make a 

submission to the Administrator that 

would identify: Each person having (as 

of the last day of the control period) a 

legal, equitable, leasehold, or 

contractual reservation or entitlement in 

the Transport Rule units at the source; 

and the percentage of each such 

person’s reservation or entitlement. 

Third, by September 15, the 

Administrator would calculate, for each 

state identified in the August 1 notice 

and for each owner of covered units in 

the state, the owner’s share of 

emissions, the owner’s share of the state 

budget with the variability limit, and 

the amount (if any) that the owner 

would be required to hold for surrender 

under the assurance provisions (i.e., the 

owner’s proportionate share of the 

excess of state emissions over the state 

budget with the variability limit). The 

Administrator would promulgate a 

notice of availability of the results of 

these calculations, provide an 

opportunity for submission of 

objections, and promulgate by 

November 15 a second notice of 

availability of any necessary 

adjustments to the calculations and the 

reasons for accepting or rejecting any 

properly submitted objections. 

By December 1, each owner identified 

in the November 15 notice as being 

required to hold allowances for 

surrender under the assurance 

provisions would designate a 

compliance account of one of its 

covered units in the state, and the 

authorized account representative of the 

compliance account would submit to 

the Administrator a statement 

designating the compliance account, as 

the account in which the required 

allowances would be held. 

As of midnight of December 15, the 

owner would have to have in its 

designated compliance account, or have 

a properly submitted transfer that would 

move into that compliance account, the 

amount of allowances (usable for 

compliance) that the Administrator 

determined (in the calculations 

referenced in the November 15 notice) 

were required to be held by the owner 

for surrender. The authorized account 

representative could identify specific 

allowances to be deducted but, in the 

absence of such identification or in the 

case of a partial identification, the 

Administrator would deduct allowances 

on a first-in, first-out basis. 

The potential effect of subsequent 

data revisions that would otherwise 

change the data used in and the results 

of the Administrator’s calculations 

referenced in the August 1 or November 

15 notices discussed previously would 

be limited. If data used in a notice 

applying the assurance provisions to a 

given year were revised as a result of a 

decision in, or settlement of, litigation 

(such as an administrative appeal 

resulting in such decision or settlement 

or an administrative appeal whose 

results were in turn appealed in a 

judicial proceeding resulting in such 

decision or settlement) initiated within 

30 days of the promulgation of the 

notice involved, then the Administrator 

would use the revised data for the 

calculations in the respective notice. 

Any other data revisions would not be 

used to revise the calculations. The 

revised data could be used, if relevant, 

in the Administrator’s calculations in 

future notices promulgated for a later 

year. If the revised calculations 

increased the amount of allowances that 

an owner was required to hold for 

surrender, the Administrator would set 

a new, reasonable deadline for the 

owner to hold the additional allowances 

in the owner’s designated compliance 

account. The Administrator believes 

that this limitation on the effect of data 

revisions on the calculation of the 

amount of allowances owners would 

have to surrender under the assurance 

provisions is necessary. Because an 

owner’s surrender obligation would be 

calculated using large amounts of data 

involving all the covered units in a state 

(including potentially many units 

owned by other owners), each owner 

would face the potential that changes in 

data outside of the owner’s 

responsibility and control could 

change—after the December 15 

allowance-holding deadline—in a way 

that would increase his surrender 

obligation after that deadline and put 

him in violation of the regulations and 

the Act. EPA believes that this potential 

risk would be significant enough that it 

could make many owners reluctant to 

consider any compliance options 

involving even the limited interstate 

trading allowed under the proposed 

remedy. The proposal would limit this 

risk by having the Administrator only 

take account of data revisions resulting 

from decisions in, or settlement of, 

litigation initiated soon after 

promulgation of the notice involved. 


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Owners’ potential allowance surrender 

obligations as of the December 15 

allowance-holding deadline under the 

assurance provisions would still be 

significant even with this limitation on 

the potential for the surrender 

obligations to increase after December 

15 due to data revisions. 

As discussed previously, it would not 

be a violation of the CAA for total state 

EGU emissions to exceed the state 

budget with the variability limit or for 

an owner to become subject to 

allowance surrender under the 

assurance provisions. However, the 

failure of an owner to hold in the 

designated compliance account a 

sufficient amount of allowances to 

satisfy this allowance surrender would 

violate the CAA and be subject to 

discretionary penalties, with each 

required allowance that was not held 

and each day of the control period 

involved constituting a violation. EPA 

believes that the allowance surrender 

requirement alone—and certainly when 

coupled with the potential for large 

discretionary penalties—would ensure 

that owners would take actions to avoid 

having total state EGU emissions exceed 

the level that would trigger the 

allowance surrender. 

(x) §§ 97.426 Through 97.428, 97.526 

Through 97.528, 97.626 Through 

97.628, and 97.726 Through 97.728— 

Miscellaneous Provisions 

These sections would allow banking 

of the allowances issued in the 

Transport Rule trading programs, i.e., 

the retention of unused Transport Rule 

allowances allocated for a given control 

period for use or trading in a later 

control period. Banking would allow 

sources to make emissions reductions 

beyond required levels and bank the 

unused allowances for use or trading 

later. This would encourage 

development of emissions reductions 

techniques and technologies and 

implementation of early reductions, 

stimulate the allowance markets, and 

provide flexibility to owners and 

operators. While this could also 

potentially cause emissions from 

sources in some states in some control 

periods to be greater than the 

allowances allocated for those control 

periods, the assurance provisions would 

limit such emissions in a way that 

would ensure that the part of each 

state’s significant contribution and 

interference with maintenance that EPA 

has identified in today’s proposed 

action would be eliminated. 

These sections also would provide 

that the Administrator could, at his or 

her discretion and on his or her own 

motion, correct any type of error that he 

or she finds in an account in the 

Allowance Management System. In 

addition, the Administrator could 

review any submission under the 

Transport Rule trading programs, make 

adjustments to the information in the 

submission, and deduct or transfer 

allowances based on such adjusted 

information. 

(5) Emissions Monitoring, 

Recordkeeping, and Reporting 

Sections 97.430 through 97.435, 

97.530 through 97.535, 97.630 through 

97.635, and 97.730 through 97.735 

would establish emissions monitoring, 

recordkeeping, and reporting 

requirements for Transport Rule units 

that would result in clear, consistent, 

rigorous, and transparent monitoring 

and reporting of all emissions. Such 

monitoring and reporting would be the 

basis for holding sources accountable 

for their emissions and would be 

essential to the success of the Transport 

Rule trading programs. This is because 

consistent and accurate measurement of 

emissions would be necessary to ensure 

that each allowance would actually 

represent one ton of emissions and that 

one ton of reported emissions from one 

source would be equivalent to one ton 

of reported emissions from another 

source. This would establish the 

integrity of each allowance and instill 

confidence in the underlying market 

mechanisms that would be central to 

providing sources with flexibility in 

achieving compliance. Moreover, given 

the variation in the type, operation, and 

fuel mix of sources covered by the 

proposed Transport Rule trading 

programs, EPA believes that emissions 

would need to be monitored 

continuously in order to ensure the 

precision, reliability, accuracy, and 

timeliness of emissions data supporting 

the trading programs. 

In §§ 97.430 through 97.435, 97.530 

through 97.535, 97.630 through 97.635, 

and 97.730 through 97.735, EPA 

proposes the monitoring, recordkeeping, 

and reporting requirements for the 

Transport Rule 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 EPAadministered trading programs, e.g., the 

ARP and NOX Budget and CAIR trading 

programs. 

Part 75 was originally developed for 

the ARP and addressed SO2 mass 

emissions and NOX emissions rate. The 

ARP, as established by Congress in CAA 

Title IV, requires the use of continuous 

emission monitoring systems (CEMS) or 

an alternative monitoring system that is 

demonstrated to provide information 

with the same precision, reliability, 

accuracy, and timeliness as a CEMS. 

Subsequently, Part 75 was expanded, for 

purposes of the 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 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 


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properly, standard substitute data 

procedures are applied and result in a 

conservative estimate of emissions for 

the period involved. This ensures a 

level playing field among the regulated 

units, with consistent accounting for 

every ton of emissions, and also 

provides an incentive to properly 

maintain, and meet the QA 

requirements for, each monitoring 

system. The monitoring and reporting 

provisions in the proposed Transport 

Rule trading program regulations would 

contain the same QA requirements and 

substitute data procedures as in Part 75 

and would reference the applicable 

provisions in Part 75. 

Part 75 requires electronic 

submission, to the Administrator and in 

a format prescribed by the 

Administrator, of a quarterly emissions 

report containing all of the emissions 

data specified in the recordkeeping 

provisions of Part 75. EPA has found 

that centralized, electronic reporting 

using a consistent format is necessary to 

ensure consistent review and public 

posting of the emissions data for 

covered units, which contribute to the 

integrity, efficiency, and transparency of 

trading programs. Further, the inclusion 

of all emissions data in a single 

quarterly report for each unit means 

that, if the same data are needed for 

multiple trading programs, the unit only 

needs to report it once in the form of 

one comprehensive report. The 

reporting provisions in the proposed 

Transport Rule trading program 

regulations would contain the same 

requirements for submission to the 

Administrator of electronic, 

comprehensive quarterly reports as in 

Part 75. As discussed above, the 

reporting provisions would also include 

a process for resubmission of quarterly 

reports where appropriate. 

5. State Budgets/Intrastate Trading 

Remedy Option 

As noted earlier in this preamble, in 

addition to the remedy option included 

in the proposed FIPs, EPA is taking 

comment on two alternative options for 

eliminating all or part of the emissions 

in upwind states that significantly 

contribute to nonattainment or interfere 

with maintenance in downwind states. 

The first of these alternative options is 

the State Budgets/Intrastate Trading 

option described below. EPA is 

considering the relative merits of this 

option and requests comment on 

whether it should be included in the 

final FIPs. EPA also identifies below a 

number of disadvantages that raise 

concerns for EPA and are explained 

later in this section. EPA requests 

comment on these issues and their 

impacts on and significance for any 

final rule. 

a. Description of Option 

The State Budgets/Intrastate Trading 

option would set state-specific caps for 

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 statespecific caps would ensure that all 

required reductions occur within the 

state and thus would address the Court’s 

concerns about abating each individual 

upwind state’s unlawful emissions 

under CAA section 110(a)(2)(D)(i)(I). 

Similar to other trading programs, the 

owners and operators of each source 

would be required to surrender to EPA 

one allowance for every ton of 

emissions after the end of every control 

period. However, a source could only 

use, for compliance with this 

requirement, an allowance issued for 

the state where the source was located. 

For purposes of obtaining allowances 

usable in compliance, sources within 

each state could trade allowances 

amongst themselves, but not with 

sources located in other states. Total 

emissions in each state could not exceed 

that state’s budget and there would be 

no shifting of emissions to other states 

thus ensuring that each state’s 

contribution to nonattainment and 

interference with maintenance with 

regard to downwind states would be 

adequately addressed. Banking of 

allowances for use in a later period 

would be permitted under this remedy 

option. 

Under this option, EPA would 

allocate allowances to the covered 

sources within each state, and sources 

in the state could use for compliance 

only allowances issued for the same 

state. Even a company that operates 

EGUs in multiple states would not be 

permitted to use for compliance for one 

of its sources allowances issued to 

another of its sources in a different state. 

In essence, this approach, if 

implemented, would result in 28 

separate trading programs for 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 for emissions variability. EPA 

also requests comment on whether 

assurance provisions based on 

variability limits should be included in 

this option. 

b. How the Option Would Be 

Implemented 

(1) Applicability 

Applicability would be the same for 

the proposed remedy and for the two 

alternative options, including this one. 

Refer to section V.D.4 above for detailed 

discussion on applicability. 

(2) Allocation of Emissions Allowances 

While the general approach for 

calculating allowance allocations would 

be the same as described above for State 

Budgets/Limited Trading, EPA would 

not distribute all of the allowances into 

the source accounts each period. The 

distribution of allowances would be 

modified because of the concentrated 

nature of numerous state power 

markets, which would be reflected in 

the state allowance markets if all 

allowances were distributed in each 

state based on factors reflecting 

generation in that state. The electric 

power sector tends to be highly 

concentrated, and, within a state, the 

majority of generation is often owned by 

a relatively small number of companies. 

This assessment of state electricity 

markets is supported by analysis using 

the Herfindahl-Hirschman Index, a way 

to measure the size of firms in relation 

to the industry and an indicator of the 

amount of competition among them (see 

Electric Generation Ownership, Market 

Concentration and Auction Size 

Technical Support Document). To 

address this potential issue concerning 

the allowance markets in many states, 

under this option some allowances 

would be withheld from certain sources 

in each state that control a large share 

of fossil-fueled power generation and 


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would be made available for companies 

with a small share of generation in the 

state. 

The reason for including this 

provision is that the dominant power 

generation companies in each state 

would likely receive a large share of the 

allocated allowances and as a result 

might be able to exert control over 

allowance prices in the state’s 

allowance market. This market power 

and potential for allowance price 

manipulation could pose a threat to the 

transparency and liquidity of allowance 

markets and put small owners of fossilfuel fired generation at a disadvantage 

regarding their compliance costs unless 

the owners were given sufficient access 

to allowances other than through direct 

purchase from the state’s dominant 

companies. Some of these owners of a 

small share of generation might already 

face higher control costs, higher 

transaction costs, and less flexibility 

regarding compliance options. 

Moreover, the use of allowance 

market power to manipulate prices 

could have wider impacts on electricity 

markets as a whole, electricity prices, 

and electricity reliability both within 

and across state borders. Therefore, the 

State Budgets/Intrastate Trading 

approach needs to address the potential 

for excessive market power and ensure 

that allowances would be available to 

all covered sources at reasonable market 

prices. 

In order to address the potential 

market power issue, under this option, 

not all allowances would be allocated 

using the allocation method described 

above in section V.D.4. Rather, a small 

portion of allowances would be 

withheld from companies with a large 

share of a state’s total fossil-fuel fired 

electricity generation. These allowances 

would be made available for purchase 

by companies with a small share of 

generation through an annual auction. 

EPA is soliciting comments on 

whether a potential market power 

problem could arise or reasons why 

market manipulation would not be a 

concern under this alternative remedy. 

EPA is also soliciting comments on 

whether the approach of using an 

annual auction to make allowances 

available to small generators would 

satisfactorily address this potential 

issue. This approach is detailed in 

subsection (3) below. 

The approach described for new unit 

set-asides and allocations to nonoperating units above for State Budgets/ 

Limited Trading in section V.D.4 would 

remain the same for this option. 

(3) Auction of Emissions Allowances 

The use of an annual allowance 

auction would ensure that companies 

with a small market share in a state 

would have access to additional 

allowances, if needed, other than 

through direct purchase from a large 

owner of generation and would reduce 

the opportunity for market price 

manipulation by dominant companies. 

This means that EPA would hold a total 

of 82 auctions every year to separately 

auction 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. 3302. 

EPA would use auctions to address 

market power concerns rather than 

other options it considered. The Agency 

considered using a different allowance 

allocation method that would take into 

account an owner’s share of total 

generation and distribute proportionally 

more allowances to owners of a small 

share of the total generation in each 

state. This would also ensure that small 

owners had sufficient allowances 

without relying on the open markets. 

However, EPA opted to use an 

allocation methodology based directly 

on the approach used to quantify each 

state’s significant contribution to ensure 

that a direct link exists between 

allocations and significant contribution 

to nonattainment or interference with 

maintenance. EPA also considered 

direct sales of allowances withheld from 

dominant sources but believes that 

auctions would be better suited for 

determining the appropriate prices for 

allowances than EPA would be at 

setting fixed allowance prices for all 

trading programs in all states. For these 

reasons, EPA believes the use of 

auctions would be the best method to 

address the issue of potential allowance 

market manipulation. 

EPA prefers to use the single-round, 

uniform-price, sealed bid format 

because it is simple for all participants 

to understand, relatively simple to 

implement and administer, and deters 

collusion among bidders. In addition, 

the utility sector already is familiar with 

this type of format, and EPA has several 

years of experience running singleround, sealed-bid auctions for Title IV 

SO2 allowances. Other formats 

considered such as multi-round 

auctions are believed to be more 

complicated for participants to 

understand and more complex to 

administer and do not discourage 

collusion. 

Entities that meet the following 

criteria would be eligible to participate 

in the allowance auction: (1) They are 

required to hold allowances in the state 

for compliance; and (2) they own no 

more than 10 percent of the total fossilfuel fired generation within the state 

based on EPA’s modeled generation for 

2014. EPA considered a range from 5 to 

20 percent share of ownership for all 

states and believes that 10 percent 

ownership is appropriate for 

determining what constitutes a small 

market share for this rule. EPA believes 

that by limiting the auction to entities 

that own no more than 10 percent of the 

fossil-fuel fired generation in a state, it 

would ensure that each auction has 

enough participants to make auctions 

viable and competitive and also ensure 

that the allowances are available only to 

those companies that may be at a 

disadvantage in the open markets. 

Companies with more than a 10 percent 

share of generation tend to operate 

several units, have more flexibility, 

receive a significant share of 

allowances, and face lower control and 

transaction costs. EPA is requesting 

comment on the share of electric 

generation used as a threshold for 

determining participation in auctions 

and also the percentage of allowances 

available through auctions. 

To implement this option, EPA would 

withhold 2 to 5 percent of the 

allowances that would be allocated to 

companies with more than 10 percent of 

the generation in order to supply 

allowances for auction each period. This 

amount is small enough not to have a 

significant impact on those EGUs from 

which the allowances are withheld and 

large enough to provide a sufficient 

number of allowances for auction. In 

more highly concentrated states where 

few companies control much of the 

generation, a relatively greater number 

of allowances would be available 

through the auction to the smaller, 

potentially disadvantaged companies. 

Conversely, in states where the 

electricity sector is less concentrated, 

there is less threat of market 

manipulation and greater likelihood of 

liquid markets. Thus, in these states 

relatively fewer allowances would be 

withheld for auction. 

Another variation on this alternative 

option would be to divide companies in 

each state into three groups, instead of 


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just two. The first group would be the 

companies that own no more than 10 

percent of the total fossil-fuel generation 

within the state and would be able to 

participate in EPA’s allowance auctions. 

The second group would be companies 

that own a medium amount of fossilfuel fired generation (for example, 

between 10 to 20 percent of the total). 

These companies would not be allowed 

to participate in auctions but also would 

not have to contribute any allowances to 

the auctions. Finally, the third group 

would be those remaining companies 

that own a large share of fossil-fuel 

generation (for example, more than 20 

percent of the total). A small percentage 

of the allowances allocated to these 

companies would be withheld to supply 

the auctions. EPA is asking for 

comments on this variation on the 

alternative option and other ways to 

address potential market power 

problems and on this alternative option. 

(4) Allowance Management System 

The allowance management system 

for the State Budgets/Intrastate Trading 

option would be consistent with the 

allowance management system for the 

State Budgets/Limited Trading programs 

described above, and with the data 

system structure EPA has developed for 

allowance management under its 

existing cap and trade programs such as 

the CAIR and the Acid Rain Program. 

(5) Monitoring and Reporting 

Monitoring and reporting provisions 

would require complete, quality-assured 

monitoring, and timely reporting of 

emissions to assure accountability and 

provide public access to data, and 

would be the same for EPA’s proposed 

remedy and the State Budgets/Intrastate 

Trading option. Refer to section V.D.4 

above for detailed discussion on 

monitoring and reporting requirements. 

(6) Penalties 

Under the State Budgets/Intrastate 

Trading option for an annual control 

program (i.e., any of the 28 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 in the State Budgets/ 

Limited Trading remedy) are necessary 

to ensure that each state eliminates the 

portion of significant contribution and 

interference with maintenance that EPA 

has identified in today’s action. EPA 

requests comment on this conclusion. 

c. How the State Budgets/Intrastate 

Trading Remedy is Consistent With the 

Court’s Opinions 

The state budgets/intrastate trading 

remedy, by establishing state-specific 

caps on annual or ozone-season EGU 

emissions, directly implements the 

section 110(a)(2)(D)(i)(I) requirement 

that emissions from sources that 

contribute significantly to 

nonattainment in, or interfere with 

maintenance by, any other state with 

respect to any such national primary or 

secondary ambient air quality standard 

be prohibited. Of the three remedy 

options considered, this option provides 

the most certainty regarding total annual 

or ozone-season emissions from each 

state. For this reason, it most directly 

addresses the statutory mandate that the 

emissions reductions occur ‘‘within the 

State.’’ 

To implement this remedy option, 

EPA would use the state budgets 

without variability limits, developed in 

accordance with the procedures 

described in sections IV.D and IV.E. 

These budgets represent EPA’s 

projection of each affected state’s EGU 

emissions in an average year (before 

accounting for the inherent variability 

in power system operations) after the 

elimination of all emissions that EPA 

has identified as significantly 

contributing to nonattainment or 

interference with maintenance. 

The number of allowances in each 

state budget would be distributed or 

made available (through an auction or 

otherwise) to sources in that state. Only 

allowances distributed or made 

available to sources in a particular state 

could be used by sources in that state to 

satisfy the requirement to hold one 

allowance for every ton of emissions. 

Thus, annual (or ozone season) 

emissions in the state would be capped 

at the level of the state budget. The 

limited variability due to banking of 

emissions could allow limited temporal 

shifting of emissions, but would not 

alter the requirement that reductions 

occur within the state. This remedy is 

thus sufficient to ensure that all 

significant contribution and interference 

with maintenance identified by EPA in 

today’s action is eliminated. 

d. Electric Reliability Issues 

EPA requests comments about 

whether the State Budgets/Intrastate 

Trading alternative option could have 

adverse consequences for electric 

reliability. The grid regions, and the 

movement of electricity within each 

grid region, do not correspond with, and 

are not limited by, state borders. For 

example, an increase in electricity 

demand (e.g., due to a hot summer), or 

a decrease in electricity supply (e.g., 

due to a major generation capacity 

outage), in a given state will not 

necessarily be met, or offset, through 

increased electricity generation in that 

same state. Instead, the increased 

demand or reduced supply may well 

result in increased generation outside 

that state. The sources of the increased 

generation will be determined by 

availability and economics and will not 

necessarily be confined to generation 

sources in that state. In fact, the ability 

to obtain additional or replacement 

supply from sources in another part of 

the state or from another state enhances 

electric reliability. 

Although companies in one state 

obtain electricity from sources in 

multiple states, the State Budgets/ 

Intrastate Trading option would 

establish emissions budgets on a state 

basis and would not allow sources in 

one state to use allowances issued to 

sources in other states. A source could 

use, in covering emissions for the 

current year, both allowances allocated 

for the current year and banked 

allowances issued by its state for a past 

year. However, this option would 

provide sources less trading flexibility 

than the proposed State Budgets/ 

Limited Trading remedy. The other 

remedy options allow for emissions 

variability, which should largely 

address electric reliability concerns. 

EPA requests comment on whether 

the State Budgets/Intrastate Trading 

alternative would provide sufficient 

flexibility for reliable operation of the 

integrated grid and, if not, whether there 

would be ways of preventing or 

reducing adverse effects such as 

including additional emissions 

variability provisions in this option or 

other approaches. EPA requests 

comment on approaches to provide 

additional emissions variability, or 

other approaches to increasing 

flexibility, in this option that would be 

consistent with eliminating all or part of 

the significant contribution and 

interference with maintenance that EPA 

has identified. 


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102 Joskow, Paul and Edward Kahn, 2002. A 

Quantitative Analysis of Pricing Behavior In 

California’s Wholesale Electricity Market During 

Summer 2000: The Final Word. 

103 Kolstad, Jonathan T. and Frank A. Wolak, 

2003. Using Environmental Emissions Permit Prices 

to Raise Electricity Prices: Evidence from the 

California Electricity Market. Published by 

University of California Energy Institute. 

104Holland, 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. 

e. How Smaller Market Trading 

Programs Have Worked 

These examples of small trading 

programs below are relevant to further 

understanding of the State Budgets/ 

Intrastate Trading remedy option. While 

small trading programs can succeed, 

they can also have serious consequences 

for allowance and electricity markets. 

Budgets and caps, allowance 

availability, and prices all can have a 

profound impact on generation and 

energy prices for consumers in addition 

to any air quality benefits. In addition, 

states range in size and number of 

potential program participants making 

each state’s circumstances unique and 

more challenging for EPA to monitor. 

(1) Texas Mass Emissions Cap and 

Trade (MECT) 

EPA has approved a 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 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 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 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.102 While the 

California crisis was the result of several 

malfunctions in the market, the RTC 

price spike was exacerbated by a 

number of factors starting with the fact 

that few emissions reductions had been 

made in earlier years. Prior to 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 were partly caused by the high 

demand for credits resulting directly 

from the manipulation of the power 

market by generators.103

The operation of the RECLAIM market 

also contributed to the high prices in the 

overall power markets. During this 

period, generators would pay 

excessively high prices for RTCs in 

order to raise the price of southern 

California generation needed to meet 

demand in the California Independent 

System Operator (CAISO). 

Subsequently, generation with high RTC 

costs in the RECLAIM area would be 

used to set the electricity price for all of 

California. The result was that 

generators could then collect excessive 

profits on their generation located 

outside the RECLAIM area. In addition, 

RECLAIM’s overlapping compliance 

cycles and assignment of facilities to 

one of two compliance cycles appears to 

have contributed to some confusion 

among the participants in the 

markets.104 Since that time, significant 

changes have been adopted to improve 

the program. 

According to the audit report for the 

2007 compliance period, total aggregate 

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. 


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f. Why This Is Not the Preferred Option 

As explained above, EPA is requesting 

comment on a State Budgets/Intrastate 

Trading remedy as an alternative option 

because this option would provide 

certainty regarding emissions from each 

state. However, this option would be 

more resource intensive, more complex, 

less flexible, and potentially more 

susceptible to market manipulation than 

the other options on which EPA is 

taking comment. 

Although this remedy may be 

perceived as relatively easy to 

understand and follow, it would 

actually be more burdensome to 

administer due to the number of trading 

programs that would be required to 

operate simultaneously and annual 

auctions that would be held every year 

to address the issues of market power 

within states. It would also result in a 

greater burden for participants operating 

EGUs in several states. Finally, EPA is 

asking for comment on whether this 

option raises electric reliability issues 

since sources would have less flexibility 

and fewer options for compliance. EPA 

is requesting comments on this 

approach, specifically on alterations 

that could address the drawbacks 

identified above or on any other 

weaknesses of this option not identified 

by EPA. EPA also welcomes comments 

regarding the validity of the concerns 

with this approach identified above. 

6. Direct Control Remedy Option 

The second alternative option on 

which EPA is requesting comment is the 

direct control option described in this 

section. EPA is considering the relative 

merits of this option and requests 

comment on whether a direct control 

remedy option should be included in 

the final FIPs. 

There are a variety of ways to 

construct a direct control option. The 

approach that EPA is presenting as an 

alternative to the remedy in the 

proposed FIPs would assign emissions 

rate limits to individual sources. 

Emissions limits would take the form of 

input-based emissions rate limits (lb/ 

mmBtu). 

EPA requests comments on the direct 

control remedy summarized later and 

the approach for determining emissions 

rate limits, which is described in greater 

detail in the ‘‘State Budgets, Unit 

Allocations, and Unit Emissions Rates’’ 

TSD in the docket for this rulemaking. 

Specifically, EPA requests comment on 

the general use of a direct control 

remedy as well as the specific rate-based 

direct control approach described later. 

EPA also requests comment on the 

potential weakness of this remedy 

option identified in the discussion later. 

In addition, EPA requests comment on 

alternate methodologies which could be 

used to implement a direct control 

remedy. 

See section V.E. later for projected 

costs and emissions associated with this 

option. 

a. Description of Option 

Unlike the proposed remedy option 

(State Budgets/Limited Trading) and the 

other alternative remedy option 

(Intrastate Trading) discussed 

previously, which both use flexible capand-trade approaches, a direct control 

remedy would directly regulate 

individual sources. Under this direct 

control remedy alternative, each owner 

of EGUs would be required to meet 

specified average emissions rate limits 

covering all of its EGUs in each covered 

state. In a state covered for the 24-hour 

and/or annual PM2.5 NAAQS, the direct 

control remedy option would require 

each company within the state to meet 

specified EGU annual emissions 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 emissions 

rate limits for NOX. EPA would set 

emissions rates on a unit-by-unit basis 

in all covered states (see approach to 

determine emissions rate limits, later). 

While emissions rates in all states 

would be set on a unit-by-unit level, a 

company would be allowed to average 

the emissions at its units within each 

state to meet the specified within-thestate rate limits. Company-level average 

rates would be calculated as companylevel total emissions divided by 

company-level total heat input in each 

state. Analogously, allowable companylevel average rates would be calculated 

using unit-specific rate limits and the 

heat inputs used to determine those 

allowable rates (as discussed in 6.b.1). A 

company that exceeded the applicable 

average rate limits would be subject to 

penalties (described later). 

In addition, to address the potential 

variability in annual emissions 

associated with emissions rate limits 

(i.e., not all years are average), starting 

in 2012, each state’s total annual (or 

ozone season, as applicable) EGU 

emissions would also be capped. 

Emissions from EGUs in each state 

would be limited to the state’s 

emissions budget with the variability 

limit. Each state’s EGU emissions would 

be capped in the following two ways. 

First, the state’s EGU emissions would 

not be permitted to exceed the state 

budget with the state’s 1-year variability 

limit in any year (or ozone season, as 

applicable). Second, on average, the 

state’s EGU emissions would not be 

permitted to exceed the budget with the 

state’s 3-year variability limit, evaluated 

as a 3-year rolling annual (or ozone 

season) average (or, in 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 the company’s 

share of the state budget with variability 

limit would be subject to a penalty. 

These assurance provisions are designed 

to assure that emissions in each covered 

state do not exceed the state’s budget 

with variability limit. They are 

described later. EPA also believes the 

penalty provisions described later are 

sufficient to ensure that these caps 

would not be exceeded. 

To implement this remedy option, 

EPA would determine unit-level 

emissions rate limits for 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 of each 

pollutant from these units would sum to 

each state’s emissions budget for the 

pollutant without the variability limit. 

The method for determining these rate 

limits is described later. 

An alternative direct control approach 

would be to create individual unit-level 

annual emissions caps (e.g., tons/year) 

in order to cap emissions in each state. 

However, this approach would greatly 

limit operational flexibility and increase 

risk to electric reliability. For example, 

a unit-level annual emissions cap 

approach could prevent a peaking unit 

from running at a time when the unit is 

necessary for electric reliability. EPA 

does not believe that a unit-level annual 

emissions cap approach is workable. 

b. How the Option Would Be 

Implemented 

(1) Approach To Determine Emissions 

Rate Limits 

To implement this remedy option, 

EPA would determine unit-level 

emissions rate limits for SO2, NOX

annual, and NOX ozone season, for 

covered EGUs in the covered states. 


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Emissions rate limits would be set at 

levels such that, if the units operated at 

the levels assumed in determining the 

state budgets, total emissions from these 

units would sum to the state budgets. In 

a state covered for purposes of the PM2.5

NAAQS, EPA would determine SO2 and 

NOX annual emissions rate limits for 

each covered EGU. In a state covered for 

purposes of the 8-hour ozone NAAQS, 

EPA would determine NOX ozone 

season emissions rate limits for each 

covered EGU. 

Emissions rate limits for Phase I (2012 

and 2013). State budgets were derived 

from the lower of available 2007–2009 

quarterly emissions or IPM base case 

projections for 2012, at the state level. 

Analogous to state budget calculation, 

EPA would base the Phase I annual 

emissions rate limit on either the unit’s 

reported annual emissions rate or the 

IPM projected rate. Rates based on 

reported data would be calculated using 

the most recent first, second, third, and 

fourth quarters of emissions data 

reported to EPA, between the first 

quarter of 2007 and the third quarter of 

2009, where four such quarters of 

reported data are available. EPA would 

determine ozone season rates based on 

a unit’s most recent ozone season 

emissions reported to EPA during the 

period of 2007–2009, if available, and 

projections or source-specific judgments 

otherwise. 

For units where EPA is aware that 

SO2 or NOX controls will be installed by 

2012 and such controls were not 

reflected in the unit’s reported 

emissions rate as determined previously 

(i.e., the control was not in operation 

during the period of time on which 

emissions limits were based), EPA 

would determine the Phase I emissions 

rate limit as the historic rate adjusted 

(reduced) to reflect operation of the 

planned control equipment at an 

emissions rate consistent with operation 

of that equipment. Emissions rate limits 

would be determined based on the 

assumption that units operate all 

existing 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 emissions 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 

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 

unit-level analysis required to establish 

such limits would be extremely 

complex, and could impact the ability of 

EPA to require the reductions as quickly 

as under other remedy approaches. 

EPA is also taking comment on an 

alternative approach for setting 

emissions rate limits for those units 

which did not report a first, second, 

third, and fourth quarter of 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 broadlydefined group could achieve their rate 

limits, it would be necessary to either 

establish limits that are fairly weak so 

that the poorest-performing units could 

meet the requirements (‘‘lowestcommon-denominator’’ effect), or, 

design more stringent requirements but 

include provisions for exceptions to the 

requirements. At this time, EPA believes 

using IPM projections and sourcespecific judgments is preferable to the 

alternative of group-based limits, and 

seeks comments on this alternative. 

Emissions rate limits for Phase II 

(2014 and onward). For EGUs in states 

that are in SO2 group 1 (i.e., the more 

stringent SO2 group), EPA would further 

adjust (reduce) SO2 emissions rates for 

certain EGUs that EPA projects would 

install FGD in modeling of the proposed 

remedy option (at less than $2000 per 

ton); for such units EPA would 

determine emissions rate limits at rates 

consistent with FGD operation. For 

other covered units, Phase II emissions 

rate limits would be the same as Phase 

I limits. Again, emissions rate limits 

would be determined based on the 

assumption that units operate all 

existing 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 emissions rate limits for covered 

new units would be set equal to the 

permit rates for these units. 

EPA has calculated specific emissions 

rate limits for each existing unit that 

would be covered under this direct 

control remedy option. These unit-level 

emissions rate limits appear in a table 

entitled ‘‘Phase I and Phase II unit-level 

emissions rate limits’’ located in the 

‘‘State Budgets, Unit Allocations, and 

Unit Emissions Rates’’ TSD in the docket 

for this rulemaking. More detailed 

description of the approach is also 

provided in the TSD. EPA is requesting 

comment on this approach for 

determining the emissions rate limits 

described in the TSD and on the limits 

themselves. 

(2) Applicability 

Applicability would be the same for 

all three remedies. Refer to section 

V.D.4 previously for detailed discussion 

on applicability. 

(3) Monitoring and Reporting 

Monitoring provisions would be the 

same for all three remedies. The direct 

control option would require minor 

changes to the reporting and record 

keeping requirements due to the need to 

collect information on both emissions 

rates and mass. The provisions would 

require complete, accurate measurement 

and timely reporting of emissions to 

assure accountability and provide 

public access to data. Refer to section 

V.D.4 previously for detailed discussion 

on monitoring and reporting 

requirements. 

(4) Assurance Provisions 

As discussed previously, starting in 

2012, the direct control remedy 

alternative would include assurance 

provisions designed to assure that 

emissions in each covered state do not 

exceed the state’s emissions budget with 

variability limit. The state’s EGU 

emissions would not be permitted to 


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exceed the state budget with 1-year 

variability limit in any year (or ozone 

season, as applicable). Additionally, on 

a 3-year rolling average basis, the state’s 

EGU emissions would not be permitted 

to exceed the budget with the 3-year 

variability limit (evaluated on an annual 

or ozone season basis, as appropriate). 

Furthermore, during 2012 and 2013, 

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 a 2-year 

variability limit. Because emissions 

would be evaluated against the 3-year 

variability limit on a 3-year rolling 

average basis, the application of the 3- 

year variability limit in 2014 would also 

serve to limit emissions in 2012 and 

2013. For EGUs in 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- 

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 limit, as appropriate) on average, 

then each company with units in the 

state whose emissions in the state 

exceeded its share of the state budget 

with variability limit would be subject 

to a penalty for its share of emissions 

above the budget with variability limit. 

In the State Budgets/Limited Trading 

remedy described previously, the 

proposed assurance provisions include 

an allowance surrender requirement. 

Those assurance provisions would 

require a company to surrender one 

allowance for each ton of the company’s 

proportional share of the amount the 

state’s EGU emissions exceed the budget 

with variability limit. This allowance 

surrender requirement is in addition to 

the trading program requirement to 

surrender one allowance for every ton 

emitted. 

In the direct control alternative, 

however, allowances are not allocated to 

units therefore an allowance surrender 

requirement is not feasible. Instead, for 

this alternative, a company with 

emissions over its share of the budget 

with variability limit would be in 

violation of the CAA and subject to 

discretionary penalties. The tonnage 

amount of the company’s violation, i.e., 

the company’s excess emissions under 

the assurance provisions, would be its 

proportional share of the amount that 

the state’s EGU emissions exceed the 

budget with the variability limit. Each 

ton of the company’s excess emissions, 

as well as each day in the averaging 

period, would be a violation. 

In this direct control remedy 

alternative, a company’s share of the 

state budget with variability limit would 

be determined using the same approach 

described in the State Budgets/Limited 

Trading option, previously. That 

approach is based on allowance 

allocations; although the direct control 

remedy would not allocate allowances 

to sources, this remedy would use the 

allocation method described in State 

Budgets/Limited Trading in determining 

a company’s share of the state budget. 

The assurance provisions would 

commence in 2012 for this direct 

control option. In contrast and for the 

reasons explained in section V.D.4, for 

the proposed State Budgets/Limited 

Trading remedy, EPA is proposing to 

start applying the assurance provisions 

in 2014. The combination of 

circumstances for State Budgets/Limited 

Trading—known locations of controls 

and a price on each ton emitted— 

provides greater certainty of where 

reductions will occur during 2012 and 

2013 than would be provided by the 

direct control program. In contrast to the 

State Budgets/Limited Trading remedy, 

the direct control program does not put 

a price on emitting SO2 or NOX so does 

not provide that incentive to reduce 

emissions. Sources can increase 

generation, while meeting the emissions 

rate limits, and increase their emissions. 

For these reasons, the direct control 

program provides less certainty 

regarding the location of emissions in 

the short term. For this reason, EPA 

believes that it would be appropriate to 

apply the assurance provisions under 

this remedy option beginning in 2012. 

EPA requests comment on these 

assurance provisions. 

(5) Penalties 

As explained previously, under this 

direct control remedy approach, each 

owner of EGUs within a covered state 

would be required to meet specified 

average emissions rate limits for 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 limit, the company would 

be in violation of the CAA and subject 

to discretionary civil penalties. 

The excess emissions of the owner’s 

EGUs would be calculated as the EGUs’’ 

actual annual average emissions rate 

minus the applicable annual average 

emissions rate limit, with the difference 

multiplied by the EGUs’’ total actual 

annual heat input. Each ton of excess 

emissions, as well as each day in the 

averaging period (e.g., 365 days for an 

annual program), would be a violation 

of the CAA. The maximum 

discretionary penalty under CAA 

Section 113 is $25,000 (inflationadjusted 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. 

c. How the Direct Control Remedy Is 

Consistent With the Court’s Opinions 

The direct control remedy option 

would implement the section 

110(a)(2)(D)(i)(I) requirement that 

‘‘emissions from sources that contribute 

significantly and interfere with 

maintenance in downwind 

nonattainment areas’’ be prohibited. It 

would do so by establishing for covered 

EGUs specific emissions rate limits, 

with company-wide within state 

averaging. Emissions rates in all states 

would be set on a unit-by-unit basis at 

levels such that, if the units operated at 

the levels assumed in determining the 

state budgets, total emissions from these 

units would sum to each state’s 

emissions budgets without the 

variability limits. A company could 

average the emissions at its units within 

each state to meet specified within-thestate rate limits. This approach would 

directly limit emissions from EGUs in 

each covered state, providing assurance 

that emissions reductions would occur 

within each state consistent with the 

mandate of section 110(a)(2)(D)(i)(I). 


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Because individual EGUs would be 

required to meet specific emissions rate 

limits (with within-state company-wide 

averaging), this option would ensure 

that required controls and measures are 

installed and implemented within the 

state. The fact that emissions, after 

implementation of all controls required 

to meet the emissions rate limits, may 

vary based on the amount of generation 

in each state is not inconsistent with the 

section 110(a)(2)(D)(i)(I) requirement 

that all significant contribution and 

interference with maintenance be 

eliminated. As noted previously, 

changes in generation due to changing 

meteorology, demand growth, or 

disruptions in electricity supply from 

other units can all affect the amount of 

generation needed in a specific state and 

thus the baseline emissions from that 

state. Because baseline emissions are 

variable, emissions after the elimination 

of all significant contribution are also 

somewhat variable. 

Further, any such variation in 

emissions would be limited. As with the 

State Budgets/Limited Trading option 

described previously, no state’s EGU 

emissions would be permitted to exceed 

the state budget with variability limit in 

any year (or ozone season, as 

applicable). Nor would any state’s EGU 

emissions be permitted, on average, to 

exceed the budget plus a specified 

portion of the state’s variability limit, 

evaluated as a 3-year rolling annual (or 

ozone season) average (or, in 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. 

d. Electric Reliability Issues 

The risk to electric reliability is 

considered low under the direct control 

remedy option. Specifically, the 

provisions for the variability limits and 

company averaging within each state 

help to alleviate electric reliability 

concerns. Therefore, EGUs are expected 

to be able to both comply with their 

emissions rate limits and reliably 

provide electricity to customers. EPA 

requests comment on electric reliability 

issues. 

e. Why This Is Not the Preferred Option 

As explained previously, EPA is 

requesting comment on the merits and 

weaknesses of this direct control 

remedy option. EPA did not include this 

remedy option in the proposed FIPs; 

however, we continue to consider this 

option and are taking comment on 

whether this option should be included 

in the FIPs. This option would provide 

assurance that companies in each state 

are meeting specific emissions rate 

limits and would also ensure that 

annual emissions from each state are 

capped. Additionally, the direct control 

option may be perceived as easy to 

understand and follow. Nonetheless, at 

this time, EPA believes the direct 

control option is inferior to the 

preferred approach. EPA requests 

comments on the validity of EPA’s 

concerns regarding this option and 

alternative methods for addressing those 

concerns. 

EPA modeling projects fewer 

emissions reductions under the direct 

control alternative than the proposed 

State Budgets/Limited Trading remedy. 

Additionally, the reductions would be 

achieved at a higher cost than the 

proposed remedy. See section V.E. for 

projected costs and emissions. 

A direct control program must 

account for outliers, e.g., units that can 

not install controls due to space 

limitations. EPA believes that the 

within-the-state company-wide 

averaging in the direct control 

alternative on which EPA is taking 

comment likely mitigates this concern. 

However, this averaging approach may 

put an owner with a small number of 

units within a state at a disadvantage 

compared to an owner with a larger 

number of units. EPA requests comment 

on this issue. 

Within the direct control approach on 

which EPA is taking comment, the 

assurance provisions (which limit a 

company’s emissions within a state to 

its share of the budget with the 

variability limit if the state’s budget 

with variability limit is exceeded) may 

also put an owner with a small number 

of units at a disadvantage compared to 

an owner with a larger number of units 

within a state. EPA seeks comment on 

this issue. 

A direct control program based on 

emissions rate limits does not cap 

annual emissions; if there is growth in 

fossil generation within a state, a ratebased approach alone could allow 

emissions increases. In the direct 

control approach on which EPA 

requests comment, the assurance 

provisions provide some assurance of 

achieving required reductions. 

Notably, the direct control approach 

described herein restricts compliance 

options more than a trading approach. 

EPA generally believes that granting 

more flexibility to companies in meeting 

an emissions reductions goal results in 

the ability of those companies to meet 

that goal at a lower cost and decreases 

reliability risks in the electric power 

system. While some portion of this 

effect is captured in IPM modeling (see 

section V.E. for projected costs and 

emissions), some types of unforeseen 

innovations in technology, fuel 

switching, and management cannot be 

captured by modeling. Any potential 

innovations and resulting cost savings 

are more likely to be found and utilized 

in the presence of regulatory flexibility. 

Based on historical experience, EPA 

believes that the benefits offered by a 

flexible trading approach are large and 

should be considered qualitatively, even 

if they cannot be quantified. Many of 

these benefits would be foregone under 

the direct control approach. 

E. Projected Costs and Emissions for 

Each Remedy Option 

Emission and cost projections for the 

three remedies discussed previously 

come from the Integrated Planning 

Model (IPM), a dynamic linear 

programming model of electric 

generation in the contiguous U.S. For 

each remedy, projected costs relative to 

the base case appear in Table V.E–1. 

The following section explains these 

projections in light of how the remedies 

differ and how they were represented in 

the model. The emissions projections 

below comprise fossil generation above 

25 megawatts of capacity, the units that 

would be subject to the rule. More detail 

on the modeling of costs and emissions 

can be found in the Regulatory Impact 

Analysis for the proposed Transport 

Rule and in the IPM Documentation. 

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 


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1. State Budgets/Limited Trading 

The proposed remedy of State 

Budgets/Limited Trading was modeled 

with regional emissions caps beginning 

in 2012 and state-specific emissions 

limits beginning in 2014. The statespecific emissions limits represent state 

budgets plus 3-year average variability 

limits. Because banking early reductions 

beyond the budget levels is allowed, 

2012 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 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 emissions 

rate limits commensurate with those 

used in the derivation of state budgets 

(see sections IV.D and IV.E). To 

represent assurance provisions, the 

emissions from each state were also 

constrained to the state’s budget plus 

3-year average variability limit 

beginning in 2012. For states with more 

stringent 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 

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 


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105The 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. 

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-LEVEL 105 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 

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


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TABLE V.E–6—PROJECTED STATE-LEVEL ANNUAL NOX EMISSIONS FROM ELECTRIC GENERATING UNITS IN 2014— 

Continued 

[Tons] 

Base case State budgets/ 

limited trading 

State budgets/ 

intrastate trading Direct control 

South Carolina ................................................................................. 47,742 34,735 33,781 34,616 

Tennessee ....................................................................................... 68,914 28,212 26,874 28,873 

Virginia ............................................................................................. 37,485 35,805 35,745 37,004 

West Virginia .................................................................................... 100,095 48,180 48,987 50,555 

Wisconsin ......................................................................................... 54,515 41,875 42,498 42,450 

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. 

1. Sunsetting of CAIR, CAIR SIPs, and 

CAIR FIPs 

The CAIR, CAIR SIPs, and CAIR FIPs 

would be replaced entirely by the 

Transport Rule provisions. If this 

proposed Transport Rule is finalized in 

2011, the CAIR, CAIR SIPs, and CAIR 

FIPs would sunset at the completion of 

all 2011 control period activities. 

In order to implement the sunsetting 

of the CAIR and CAIR FIPs, the 

proposed rule includes several revisions 

of the CAIR, §§ 51.123 and 51.124, and 

the CAIR FIPs, §§ 52.35 and 52.36. First, 

sunsetting the CAIR and CAIR FIPs in 

2011 would mean that the requirements 

of the CAIR and CAIR FIPs would not 

apply to control periods after 2011. 

Specifically, the CAIR would be revised 

to rescind, with regard to any control 

period beginning after December 31, 

2011, the findings that states must 

revise their SIPs to meet CAIR 

requirements. Similarly, the CAIR FIPs 

would be revised to state that, with 

regard to any post-December 31, 2011 

control period, CAIR FIP requirements 

would not be applicable. 

Second, the sunsetting in 2011 would 

mean that the CAIR trading programs 

would not continue past 2011. 

Consequently, the proposed revisions of 

the CAIR and CAIR FIPs would state 

that, with regard to any post-December 

31, 2011 control period, the 

Administrator would not carry out any 

of the functions established for the 

Administrator in the CAIR model 

trading rule, the CAIR FIPs, or any state 

trading programs approved under the 

CAIR. 

Third, the sunsetting in 2011 would 

mean that CAIR allowances allocated for 

control periods after 2011—which have 

already been recorded by the 

Administrator in the Allowance 

Management System compliance 

accounts of sources in many states— 

would not be usable in the CAIR trading 

programs for control periods ending 

before 2012. Specifically, under the 

existing CAIR trading programs, a 

source that fails to hold sufficient 

allowances to cover emissions for the 

2011 control period (whether annual or 

ozone season) must provide for 

surrender to the Administrator three 

allowances (one as an offset and two as 

an automatic penalty) allocated for the 

2012 control period for every one 


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allowance that was not held as required. 

However, consistent with the proposed 

termination of the CAIR trading 

programs for control periods after 2011, 

EPA believes that allowances allocated 

for such control periods (e.g., 2012 

allowances) should not be usable for 

any purpose. In any event, because such 

allowances would have little or no 

market value, their deduction would 

impose little or no cost on the party 

holding them. Consequently, the 

proposed revisions of the CAIR and 

CAIR FIPs would state that the 

Administrator would not deduct, for 

excess emissions, any CAIR allowances 

allocated for control periods in 2012 or 

any year thereafter. These revisions 

would ensure that no CAIR allowances 

allocated for post-2011 control periods 

would be used as an offset of, or an 

automatic penalty for, excess emissions. 

As a result of these proposed 

revisions of the CAIR and CAIR FIP 

rules, there would be no offset or 

automatic penalty deducted for a source 

that failed to hold sufficient allowances 

to cover its 2011 control period 

emissions unless the state SIPs are 

revised. In order to preserve the 

deductions for offsets and automatic 

penalties for 2011 control periods, the 

CAIR SIPs for most states (i.e., 20 out of 

the 28 states subject to at least one CAIR 

trading program) would need to be 

modified and the modified CAIR SIPs 

would need to be approved by the EPA 

—-before EPA conducts the process of 

determining source compliance after the 

allowance transfer deadline for the 2011 

control periods —in order to change the 

allocation year of the allowances 

required to be deducted (e.g., from 

allowances allocated for 2012 to 

allowances allocated for 2011). 

Although EPA’s past experience with 

trading programs strongly suggests that 

few sources would be out of compliance 

with the requirement to hold allowances 

covering 2011 emissions, all of these 

CAIR SIPs would have to be revised 

because there is no way to predict 

which few sources in which few states 

might be out of compliance in 2011 and 

the process of revising SIPs is too long 

to be started while EPA is still 

determining compliance. In fact, when 

states needed to revise their SIPs to 

include the existing requirements of 

CAIR and submit the revised SIPS to the 

Administrator, EPA found that states 

needed up to 3 years to develop and 

submit SIP revisions, and EPA needed 

about 6 months to act on the SIP 

revisions. In light of this experience 

with SIP revisions under CAIR, EPA 

believes that it would highly unlikely 

that all, or even most, state CAIR SIPs 

could be revised, submitted, and 

approved in time—even if the SIP 

revision process were started when a 

final Transport Rule is promulgated—to 

change what allowances were to be used 

for offsets and automatic penalties for 

excess emissions for the 2011 control 

periods. 

Moreover, any excess emissions for 

the 2011 control periods would be 

violations of the state SIPs (or of CAIR 

FIPs in those states with CAIR FIPs) and 

of the Clean Air Act and, therefore 

would be subject to discretionary civil 

penalties under CAA Section 113. Each 

ton of excess emissions, and each day in 

the control period involved (i.e., 365 

days for annual control periods and 153 

days for the ozone season control 

period), would be a violation, with a 

maximum penalty of $25,000 (inflation 

adjusted to $37,500) per violation. In 

determining what level of discretionary 

civil penalties to impose on a source 

that has excess emissions violations, 

EPA routinely considers, among other 

things, whether, and if so what level of, 

other penalties (e.g., automatic excess 

emissions penalties) have already been 

imposed for the same violations, as well 

as any economic benefit of 

noncompliance (e.g., the avoidance of 

the cost of surrendering allowances to 

cover emissions). See, e.g., 42 U.S.C. 

7413(e)(1) (including, as penalty 

assessment criteria, ‘‘payment by the 

violator of penalties previously assessed 

for the same violation’’ and ‘‘the 

economic benefit of noncompliance’’). 

Consequently, EPA believes that, 

regarding the CAIR 2011 control periods 

(both annual and ozone season) for 

which it is not feasible to change the 

offset and automatic penalty provisions 

to make them workable, the potential for 

assessment of significant, discretionary 

civil penalties would provide a strong 

incentive for compliance with the 

allowance-holding requirement and 

avoidance of excess emissions. 

In addition to the previouslydescribed, proposed revisions to 

§§ 51.123, 51.124, 52.35, and 52.36, 

certain provisions in part 52 that reflect, 

state by state, the CAIR SIP revisions 

and CAIR FIP requirements applicable 

to each state would need to be revised 

to implement the sunsetting of the 

CAIR, CAIR SIPs, and CAIR FIPs. 

However, the timing for proposal and 

adoption of revisions to part 52 is 

necessarily different for the part 52 

provisions addressing CAIR SIP 

revisions and those addressing revisions 

of the CAIR and the CAIR FIPs 

themselves. 

The part 52 provisions addressing 

CAIR SIP revisions for the individual 

states reflect EPA’s approval of CAIR 

SIP revisions adopted and submitted to 

EPA by the respective states. The first 

step toward sunsetting those part 52 

provisions would be that, if and after 

the proposed Transport Rule was 

finalized, the respective states would 

change their SIPs in order to, among 

other things, make the CAIR provisions 

in the SIPs inapplicable to any control 

period that starts after December 31, 

2011. After the submittal by the 

respective states of these SIP revisions, 

EPA would review and approve such 

changes. Consequently, the rule text 

approving such CAIR SIP revisions 

would not be included in either the 

proposed Transport Rule or any final 

rule based on the proposed Transport 

Rule, but rather would be proposed and 

adopted only after the respective states 

revised their SIPs. As EPA did when 

transitioning from the 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 statespecific 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 Transport Rule the proposed 

rule text making these state-by-state 

revisions for Delaware, District of 

Columbia, Indiana, Louisiana, 

Michigan, New Jersey, Tennessee, 

Texas, and Wisconsin. These provisions 

revise all of the state-specific Part 52 

provisions adopting CAIR FIPs 

provisions to make the CAIR FIPs 

inapplicable to any control period that 


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starts after December 31, 2011 and state 

that the Administrator would not carry 

out any functions under the CAIR 

trading programs during any such 

control period and would not use any 

CAIR allowances allocated for any such 

control period. 

2. Change in States Covered 

The states covered by the proposed 

Transport Rule differ slightly from states 

covered by the CAIR. Namely, as 

compared with the states covered by the 

CAIR 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 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 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 

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 emissions 

rates are nearly identical to what they 

were before the NBP started. Moreover, 

these units as a group had allowances 

that they did not need for compliance 

and that were available for trading to 

other affected units. The Transport Rule, 

as proposed, does not include these 

units and does not include provisions 

for allowing states expand applicability 

to include them. EPA is taking comment 

on this approach. 

4. Early Reduction Provisions 

Substantial emissions reductions have 

occurred as a result of the CAIR 

programs. These reductions are greater 

than were expected when the rule was 

promulgated. This is evidenced in the 

banks of allowances that exist in each of 

the CAIR programs. 

a. 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 

emissions reductions for Title IV where 

allowances are used for compliance 

with the requirement to hold allowances 

covering emissions and early reductions 

for the CAIR 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 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 for two reasons. First, the Court is 

likely to view the approach as imposing 

a significant burden on the use of Title 

IV allowances and therefore as 

modifying the authorization provided 

by such allowances. Second, the Court 

is likely to view the approach as not 

related to, much less necessary for, 

implementation of the section 

110(a)(2)(D)(i)(I) mandate to eliminate 

significant contribution and interference 

with maintenance. EPA chose instead, 

under the proposed Transport Rule, to 

distribute Transport Rule SO2

allowances in a manner directly linked 

to its calculation of each state’s 

significant contribution and interference 

with maintenance and not to use Title 

IV allowances as a basis for distributing 

the new Transport Rule allowances. 

EPA is confident that the approach 


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selected is consistent with the Court’s 

opinion in North Carolina v. EPA, 531 

F.3d 896, 922 (D.C. Cir. 2008). 

(Additional information on this 

approach can be found in the docket.) 

EPA requests comment on whether or 

not an allowance distribution approach 

based on the number of Title IV 

allowances in a given source’s account 

would be consistent with the Court 

opinion. 

EPA proposes that the Transport Rule 

provisions not allow the use of Title IV 

allowances either as the basis for 

allocating Transport Rule SO2

allowances or directly for 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 about 720,000 

allowances (which would equal nearly 

50 percent of the total of the state 

budgets under the proposed Transport 

Rule NOX annual program for 2012), 

after completion of true-up of allowance 

holdings and emissions for 2011. 

Estimates of the size of the banks have 

only recently been made based on 

reported 2009 emissions data, and the 

impacts of different approaches to 

handling the banks have not yet been 

modeled. However, EPA is concerned 

about the potential impacts of these 

approaches. On one hand, allowing pre2012 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 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 emissions 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 pre2012 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 that some 

parties may view this approach as 

having the effect of allowing sources 

that were advantaged by the 

development of state budgets using fuel 

adjustment factors—the use of which 

was reversed by the Court in North 

Carolina, 531 F.3d at 918–21—and that 

still hold part of their allocated 

allowances to continue have an 

advantage in the Transport Rule NOX

trading programs. These concerns may 

be mitigated somewhat by the fact that 

even though the methodology used to 

divide the regional budget into state 

budgets used fuel factors, states had the 

flexibility to allocate allowances 

however they wished. EPA takes 

comment on the extent to which states 

have allocated differently and the extent 

to which this may mitigate concerns 

about allowing the use of banked CAIR 

NOX allowances in the Transport Rule 

annual NOX and ozone season 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 

emissions reductions in 2010 and 2011. 

The third option might be to try to 

factor the bank into the calculation of 

state budgets by reducing the state 

budgets to take account of the banked 

pre-2012 CAIR allowances. This might 

allow these allowances to be used in the 

Transport Rule 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 be 

feasible because EPA cannot determine 

in advance in which states banked pre2012 CAIR allowances might be used 

and so would not know which state 

budgets should be adjusted and what 

amount of adjustment would be 

necessary. 

A final approach would simply be to 

not allow the use of any banked pre2012 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 pre2012 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 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 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 yearround under the CAIR and would 

continue to do so under the Transport 

Rule: Alabama, Delaware, the District of 

Columbia, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Missouri, New 

Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Virginia, West Virginia, and 

Wisconsin. Non-Acid Rain units in 

Arkansas are currently required to 

monitor and report NOX in the ozone 

season under the CAIR and would 

continue to be required to do so under 

the proposed Transport Rule. 


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Non-Acid Rain units in Connecticut 

and Massachusetts (about 15 units total) 

that currently monitor and report NOX

in the ozone season would need to 

monitor and report NOX and SO2 on an 

annual basis under the proposed 

Transport Rule. 

Non-Acid Rain units in Mississippi 

(about 4 units) and Texas (about 52 

units) are currently monitoring and 

reporting 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 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 year-round. 

Oklahoma is not covered by the CAIR 

and is covered by the Transport Rule, 

and units there would need to monitor 

and report NOX in the ozone season. 

There are about 34 non-Acid Rain units 

total in Kansas, Nebraska and Oklahoma 

not monitoring and reporting under Part 

75 that would need to begin to do so. 

Most of these units are simple-cycle 

combustion turbines used in the ozone 

season as peaking units and would 

likely be able to utilize the Low Mass 

Emissions or Appendix D and E 

methodologies in 40 CFR part 75, which 

do not require a continuous emissions 

monitoring system (CEMS). The 

circulating fluidized bed (CFB) units in 

Oklahoma (about 4 units) that burn coal 

are already monitoring and reporting 

under 40 CFR part 60, subpart Da, 

which requires an 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 

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 

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 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 Trading Program 

(NBP) to comply with the NOX SIP Call 

requirements for EGUs serving a 

generator with a nameplate capacity 

greater than 25 MW and large non-EGUs 

with a maximum rated heat input 

capacity greater than 250 MMBTU/hr. 

(In some states, EGUs smaller than 25 

MW were also part of the NBP as a 

carryover from the Ozone Transport 

Commission 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 emissions rates 

as a result of their inclusion in the CAIR 

NOX ozone season program. If EPA were 

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 


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106The 2005 findings of failure to submit related 

to states’ obligations pursuant to section 

110(a)(2)(D)(i). The CAIR, however, addressed only 

the requirements of 110(a)(2)(D)(i)(I). The remand of 

CAIR, therefore, had no impact on state SIP 

submissions or EPA approval of state SIP 

submissions pursuant to section 110(a)(2)(D)(i)(II). 

maintenance would be to require the 

budget increase to be much less than 

allowed under the NBP and CAIR. For 

example, the units’ 2009 emissions (or 

2012 projected emissions if they are 

required to install controls for another 

program) could be used to determine the 

budget increase and the elimination of 

emissions causing significant 

contribution and interference with 

maintenance might be able to be 

preserved. It is likely the budget 

changes would not be consistent across 

states as each state’s impact would have 

to be considered individually. EPA is 

proposing to not allow the expansion of 

the applicability of the Transport Rule. 

Therefore, the NBP states would need 

to achieve their NOX SIP Call emissions 

reductions another way in order to 

continue to comply with the NOX SIP 

Call. If EPA promulgates a final rule that 

does not allow the expansion of the 

Transport Rule to NBP units, any state 

that allowed these units to participate in 

the CAIR 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 

emissions 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 

ensure accuracy. Subsequent to these 

sessions, EPA received post-meeting 

comments and additional detailed 

suggestions and analyses on ways to 

address some of the issues that the court 

cited, most notably from state regional 

organizations in the eastern U.S. All the 

stakeholder-related materials may be 

found in the EPA docket for the 

transport rule (EPA–HQ–OAR–2009– 

0491). 

Following the remand of CAIR to EPA 

in December 2008, 17 states in the East 

and Midwest, under the umbrellas of 

the OTC and Lake Michigan Air 

Directors Consortium (LADCO) with 

support from southeastern states, 

worked to develop recommendations for 

EPA to consider in crafting a new 

transport rule to replace CAIR. The 

comprehensive framework presented 

the consensus approach the states 

reached but noted that certain regional 

differences would be addressed in 

separate letters with additional 

recommendations and supporting 

materials. 

EPA has considered and appreciates 

all the ideas and recommendations 

provided by the states. We are 

employing the technical work that they 

submitted as part of the data set we are 

using in this and later transport rules. 

Topics addressed in the listening 

sessions, where EPA asked stakeholders 

and regulatory partners for their 

thoughts on particular issues, included: 

• Analysis and baselines. 

• Linkages between a state’s 

significant contribution and downwind 

nonattainment/interference with 

maintenance. 

• Remedies. 

• Attainment planning. 

• Other areas. 

EPA continued to provide updates to 

regulatory partners and stakeholders 

through monthly conference calls with 

states, hosted by, e.g., NACAA, as well 

as industry and NGO conferences where 

EPA directors often made presentations. 

Several of the options presented in 

this proposal were influenced by 

feedback received from stakeholders 

and regulatory partners, including: 

• 2012 baseline used in the 

calculation of each state’s significant 

contribution and interference with 

maintenance. 

• The ‘‘tiered’’ approach to SO2

emissions reductions requirements. 

• Threshold (1 percent of the 

NAAQS) used for linking upwind areas 

to downwind nonattainment and 

maintenance receptors. 

• Approach used to give independent 

meaning to the interfere with 

maintenance prong of section 

110(a)(2)(D)(i)(I). 

• Level of reductions required. 

• Use of limited interstate trading. 

• Correlated and coordinated 

requirements and timing for the power 

industry. 

EPA looks forward to the public 

comment period of this rulemaking and 

is committed to establishing and 

maintaining close working relationships 

with a broad range of public and private 

sector organizations. 

VII. State Implementation Plan 

Submissions 

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

1997 Ozone and 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) 

obligations. In the CAIR, EPA concluded 

that the states in the CAIR region would 

meet their section 110(a)(2)(D)(i) 

obligations to address ‘‘significant 

contribution’’ and ‘‘ interference with 

maintenance’’ requirements by 

complying with the CAIR requirements. 

Consequently, states within the CAIR 

region did not need to submit a separate 

SIP revision to satisfy the section 

110(a)(2)(D)(i) requirements provided 

they submitted a SIP revision to satisfy 

CAIR. Most of the CAIR states 

participated in the CAIR trading 

programs and submitted SIP revisions 

that EPA subsequently approved. In 

2008, the Court granted several petitions 

for the review of the CAIR and found, 

among other things, that EPA had not 

demonstrated that the CAIR effectuates 

the statutory mandate of section 

110(a)(2)(D)(i)(I). The EPA approvals of 

the CAIR SIPS preceded the remand of 

the CAIR by the Court. Therefore, 

because the D.C. Circuit Court found 

CAIR and the CAIR FIPs unlawful, 

EPA’s approval of the provisions of a 

state’s SIP submittal as addressing the 

requirements of the CAIR could not 

satisfy that state’s section 

110(a)(2)(D)(i)(I) obligation. In other 

words, a CAIR SIP submission can no 

longer be considered an adequate 

section 110(a)(2)(D)(i)(I) SIP submission. 

For this reason, EPA’s 2005 findings 

that states had failed to submit SIPs that 

satisfy section 110(a)(2)(D)(i)(I) 106

remain in force regardless of whether a 

state covered by the CAIR submitted 


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107Part 70 governs approved state Title V 

programs, and part 71 governs the federal Title V 

program. 

and/or had an approved SIP stating that 

compliance with the CAIR satisfied 

their 110(a)(2)(D)(i) obligations. 

The 2005 findings of failure to submit 

also remain in force for many states not 

covered by the original CAIR. Some of 

these states have not yet submitted 

110(a)(2)(D)(i)(I) SIPs and thus the 

findings remain in force. However, 

several states that were not covered by 

the CAIR have since 2005 submitted SIP 

revisions to satisfy the requirements of 

section 110(a)(2)(D)(i) for the 1997 8- 

hour ozone and 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 

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 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 

these Transport Rule FIPs, EPA would 

in no way affect the right of states to 

submit, for review and approval, a SIP 

that replaces the federal requirements of 

the FIP with state requirements. In order 

to replace the FIP in a state, the state’s 

SIP must provide adequate provisions to 

prohibit NOX and SO2 emissions that 

contribute significantly to 

nonattainment or interfere with 

maintenance in another state or states. 

The Transport Rule FIPs would be in 

place in each covered state until a 

state’s SIP was submitted and approved 

by EPA to replace a FIP. 

For each upwind state covered by the 

proposed Transport Rule, EPA proposes 

state-specific emissions reductions 

requirements with respect to one or 

more of three air quality standards—the 

1997 annual PM2.5 NAAQS, the 2006 24- 

hour PM2.5 NAAQS, and the 1997 ozone 

NAAQS. In CAIR, EPA allowed the 

states to replace the CAIR FIP with SIPs 

and provided substantial flexibility. 

Again EPA wants to offer states 

substantial flexibility for addressing the 

Section 110(a)(2)(D)(i)(I) transport issues 

through a SIP should they choose to do 

so. The EPA’s intent is to provide states 

with substantial flexibility in 

implementing these emissions 

reductions requirements. EPA will 

allow a state to submit a SIP for the 

ozone requirements only, for the PM2.5

requirements only, or for both the ozone 

and the PM2.5 requirements. The 

specific quantity of emissions 

reductions necessary for a state’s SIP 

would be determined based on the state 

emissions budgets provided in the final 

transport rule. (See Tables IV.E–1 for 

proposed SO2 and annual NOX budgets, 

and IV.E–2 for proposed ozone season 

NOX budgets, in section IV.E). 

In the states for which EPA is 

proposing to require reductions with 

respect to both the 24-hour PM2.5

NAAQS and the annual PM2.5 NAAQS, 

there is no case where the annual 

standard drives the reduction 

requirements deeper than would the 24- 

hour standard alone. Thus, emissions 

reduction requirements for a SIP to 

address significant contribution and 

interference with maintenance with 

respect to the 24-hour PM2.5 NAAQS 

would be based on the SO2 and NOX

emissions budgets in Table IV.E–1. For 

such a state, a SIP that addresses the 

requirements with respect to the 24- 

hour PM2.5 NAAQS would also by 

definition address the requirements 

with respect to the annual PM2.5

NAAQS. 

EPA is taking comment on all aspects 

of how a state could replace the 

Transport Rule FIP with a SIP and on 

what the SIP approval criteria should 

be. 

VIII. Permitting 

A. Title V Permitting 

EPA’s proposed FIPs would not 

establish any permitting requirements 

independent of those under Title V of 

the CAA and the regulations 

implementing title V, 40 CFR parts 70 

and 71.107 Title V requires that sources 

meeting certain criteria have permits 

meeting the requirements specified in 

Title V and the Title V regulations. For 

example, for sources required to have 

Title V permits, such permits must 

include, among other things, all 

‘‘applicable requirements,’’ as defined in 

the Title V regulations (40 CFR 70.2 and 

71.2 (definition of ‘‘applicable 

requirement’’)). 

EPA anticipates that, given the nature 

of the units covered by the proposed 

FIPs, most of the sources at which they 

are located would be subject to Title V 

permitting requirements. For sources 

subject to Title V, the requirements 

applicable to them under the proposed 

FIPs would be ‘‘applicable 

requirements’’ under Title V and 

therefore would need to be included in 

the Title V permits. For example, 

requirements under the proposed FIPs 

concerning designated representatives, 

monitoring, reporting, and 

recordkeeping, the requirement to hold 

allowances covering emissions, the 

assurance provisions, and liability 

would be ‘‘applicable requirements’’ and 

necessary to include in the permits. 


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108A permit is reopened for cause if any new 

applicable requirements (such as those under a FIP) 

become applicable to a covered source with a 

remaining permit term of 3 or more years. If the 

remaining permit term is less than 3 years, such 

new applicable requirements will be added to the 

permit during permit renewal. See 40 CFR 

70.7(f)(1)(i) and 71.7(f)(1)(i). 

The Title V permits program includes, 

among other things, provisions for 

permit applications, permit content, and 

permit revisions that would address the 

applicable requirements under the 

proposed FIPs in a manner that would 

provide the flexibility necessary to 

implement a market-based program 

such as the one that EPA is proposing. 

For example, the Title V regulations 

provide that a permit issued under Title 

V must include, for any ‘‘approved 

* * * emissions trading and other 

similar programs or processes’’ 

applicable to the source, a provision 

stating that no permit revision is 

required ‘‘for changes that are provided 

for in the permit.’’ 40 CFR 70.6(a)(8) and 

71.6(a)(8). The trading program 

regulations for the proposed FIPs would 

include a provision stating that no 

permit revision is necessary for the 

allocation, holding, deduction, or 

transfer of allowances. Consistent with 

the Title V regulations, this provision 

would also be included in each Title V 

permit for a covered source. As a result, 

allowances could be traded (or 

allocated, held, or deducted) under the 

FIPs without a revision of the Title V 

permit of any of the sources involved. 

As a further example of flexibility 

under Title V, the Title V regulations 

allow the use of the minor permit 

modification procedures for permit 

modifications ‘‘involving the use of 

economic incentives, marketable 

permits, emissions trading, and other 

similar approaches, to the extent that 

such minor permit modification 

procedures are explicitly provided for in 

an applicable implementation plan or in 

applicable requirements promulgated by 

EPA.’’ 40 CFR 70.7(e)(2)(i)(B) and 40 

CFR 71.7(e)(1)(i)(B). The trading 

program regulations for the proposed 

FIPs would include provisions requiring 

unit owners and operators to submit 

monitoring system certification 

applications (or, for alternative 

monitoring systems, petitions) to EPA 

establishing the monitoring and 

reporting approach to be used by the 

unit. These applications and petitions 

are subject to EPA review and approval 

to ensure consistency in monitoring and 

reporting among all trading program 

participants. As provided in the 

proposed regulations, EPA would only 

allow use of approaches that would 

result in emissions data with an 

appropriate level of precision, 

reliability, accessibility, and timeliness. 

The proposed regulations would also 

include a provision stating that a 

description of the general approach that 

each covered unit is required to use for 

monitoring and reporting emissions 

(i.e., an approach using a continuous 

emissions monitoring system, an 

excepted monitoring system under 

appendices D and E to part 75, a low 

mass emissions excepted monitoring 

methodology under § 75.19, or an 

alternative monitoring system under 

subpart E of part 75) could be added to 

or changed in a Title V permit using 

minor permit modification procedures, 

provided that the requirements 

applicable to the monitoring and 

reporting addition or change were 

already incorporated elsewhere in the 

permit. As a result, minor permit 

modification procedures could be used 

to revise a unit’s Title V permit to be 

consistent with any changes in the 

monitoring and reporting approach 

allowed for the unit by EPA through the 

monitoring system certification or 

petition process in the proposed trading 

program regulations. However, if the 

permit did not already incorporate the 

monitoring and reporting requirements 

applicable to the change, the permit 

would also have to be revised to 

incorporate these requirements, and this 

change would not qualify as a minor 

permit modification pursuant to 40 CFR 

70.7(e)(2)(i)(B) and 40 CFR 

71.7(e)(1)(i)(B). 

As new applicable requirements 

under Title V, the requirements for 

covered units under the final FIPs 

would be incorporated into covered 

sources’ existing Title V permits either 

pursuant to the provisions for reopening 

for cause (40 CFR 70.7(f) and 40 CFR 

71.7(f)) or the permit renewal provisions 

(40 CFR 70.7(c) and 71.7(c)).108 For 

sources newly subject to title V that 

would also be covered sources under 

the proposed FIPs, the initial Title V 

permit issued pursuant to 40 CFR 

70.7(a) would include the final FIP 

requirements. In order to ensure that 

covered sources’ Title V permit 

provisions concerning the FIPs would 

reflect, properly and in a manner 

consistent from permit to permit, the 

trading program requirements and 

flexibilities, EPA intends to issue 

guidance, after promulgation of the final 

FIPs, to assist permitting authorities. 

This guidance would include 

information on permit issuance and 

permit modification requirements, as 

well as a permit content template that 

would identify the applicable 

requirements under the trading program 

and thereby ensure that they would be 

correctly and comprehensively reflected 

in each permit in a manner that would 

reduce the need for frequent permit 

revisions. Use of a permit content 

template would also reduce the burden 

on sources in obtaining, on permitting 

authorities in issuing, and on EPA in 

reviewing, permits or permit revisions. 

B. New Source Review 

EPA recognizes that pollution control 

projects, including pollution control 

projects constructed to comply with the 

proposed rule, have the potential to 

trigger new source review (NSR) 

permitting. 

On December 20, 2005, the EPA 

agreed to reconsider one specific aspect 

of the CAIR. In that notice, EPA granted 

reconsideration and sought comment on 

the potential impact of a judicial 

opinion, New York v. EPA, 413 F.3d 3 

(D.C. Cir. 2005). This decision vacated 

the pollution control project exclusion 

in EPA’s NSR regulations. (The 

exclusion allowed for certain 

environmentally beneficial pollution 

control projects to be excluded from 

certain NSR requirements.) For this 

reconsideration, EPA conducted an 

analysis which showed that the court 

decision did not impact the CAIR 

analyses. The EPA believes this 

analysis, which remains current and 

relevant for all pollutants except for 

greenhouse gas (GHG), shows that New 

Source Review (NSR) requirements 

would not significantly impact the 

construction of controls that are 

installed to comply with the proposed 

transport rule. Details of this analysis 

can be found in a Technical Support 

document which is available on EPA’s 

Web site at: http://epa.gov/cair/pdfs/ 

0053–2263.pdf. 

Because GHG was not considered by 

EPA to be a ‘‘pollutant’’, let alone a 

‘‘regulated pollutant,’’ at the time of 

CAIR, GHG was not addressed in the 

previous analysis. GHG requirements 

related to the component of new source 

review concerning the Prevention of 

Significant Deterioration (‘‘PSD’’) 

program have recently been addressed 

in EPA’s ‘‘Interpretation of Regulations 

that Determine Pollutants Covered by 

Clean Air Act Permitting Programs,’’ 75 

FR 17004 (April 2, 2010), and 

‘‘Prevention of Significant Deterioration 

and Title V Greenhouse Gas Tailoring 

Rule,’’ 75 FR (June 3, 2010) (‘‘Tailoring 

Rule’’). Generally, as discussed in those 

actions, once the PSD requirements for 

GHG take effect on January 2, 2011, 

major stationary sources will be 

required to address GHG emissions as 

part of the PSD program if these sources 

emit GHG in amounts that equal or 


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109Roman 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. 

110As 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. 

111To provide a point of reference, Table IX–1 

also includes the number of nonattainment and/ 

maintenance sites based on ambient design values 

for the period 2003 through 2007. 

exceed the thresholds in the Tailoring 

Rule. Once the PSD requirements take 

effect, major sources that undergo a 

modification, including the addition of 

pollution control equipment, will trigger 

PSD requirements for their emissions of 

GHG if such emissions increase by at 

least 75,000 tons per year of CO2

equivalent. EPA believes it is very 

unlikely that pollution control projects 

would cause GHG increases that would 

exceed the 75,000 tons per year 

threshold. 

Consistent with EPA’s previous 

analysis and EPA’s conclusions for 

GHG, EPA does not believe that there 

are significant impacts from NSR for any 

pollution control projects resulting from 

the proposed rule such as low-NOX

burners, SO2 scrubbers, or SCR. EPA 

requests comment on this issue. 

IX. What benefits are projected for the 

proposed rule? 

In this section, we present the results 

of EPA’s analysis of the benefits of the 

emissions reductions in this proposal on 

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 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 cobenefits 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.109 All 

monetized estimates are stated in 2006 

dollars. Also note that the analytic 

baseline presents a unique situation. 

EPA has been directed to replace the 

CAIR; yet the CAIR remains in place 

and has led to significant emissions 

reductions in many states. 

A key step in the process of 

developing a 110(a)(2)(D)(i)(I) rule 

involves analyzing existing (base case) 

emissions to determine which states 

significantly contribute to downwind 

nonattainment and maintenance areas. 

EPA cannot prejudge at this stage which 

states will be affected by the rule. For 

example, a state affected by CAIR may 

not be affected by the new rule and after 

the new rule goes into effect, the CAIR 

requirements will no longer apply. For 

a state covered by CAIR but not covered 

by the new rule, the CAIR requirements 

would not be replaced with new 

requirements, and therefore an increase 

in emissions relative to present levels 

could occur in that state. More 

fundamentally, the court has made clear 

that, due to legal flaws, the CAIR rule 

cannot remain in place and must be 

replaced. If EPA’s base case analysis 

were to ignore this fact and assume that 

reductions from CAIR would continue 

indefinitely, areas that are in attainment 

solely due to controls required by CAIR 

would again face nonattainment 

problems because the existing 

protection from upwind pollution 

would not be replaced. For these 

reasons, EPA cannot assume in its base 

case analysis, that the reductions 

required by CAIR will continue to be 

achieved. 

Following this logic, the 2012 base 

case shows emissions higher than 

current levels in some states. Because 

EPA has been directed to replace CAIR, 

EPA believes that for many states, the 

absence of the CAIR 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. 

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 year of 2005 for the 

eastern U.S. modeling domain.110

Modeling was performed for the 2014 

base case and the 2014 ‘‘State Budgets/ 

Limited Trading’’ scenario to assess the 

expected effects of the proposed 

regional strategy on projected 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–1.111 The average 

and peak reductions in annual PM2.5, 

daily PM2.5, and ozone predicted at 2012 

nonattainment and/or maintenance sites 

due to the emissions reductions 


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112 ‘‘Nonattainment’’ is used to denote sites that 

are projected to have both nonattainment and 

maintenance problems. 

between 2012 and the 2014 remedy are 

provided in Table IX–2. 

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) 

Percent reduction: 2014 

base case vs. 

2014 remedy 

(percent) 

Annual PM2.5 Nonattainment Sites 112 ..... 102 32 15 1 97 93 

Annual PM2.5 Maintenance-Only Sites .... 21 16 7 1 94 86 

Daily PM2.5 Nonattainment Sites ............. 151 92 54 17 82 69 

Daily PM2.5 Maintenance-Only Sites ........ 48 38 28 11 71 61 

Ozone Nonattainment Sites ..................... 103 11 7 7 36 0 

Ozone Maintenance-Only Sites ............... 67 16 6 5 69 17 

TABLE IX–2—AVERAGE AND PEAK REDUCTION IN ANNUAL PM2.5, DAILY PM2.5, AND OZONE FOR SITES THAT ARE

PROJECTED TO HAVE NONATTAINMENT AND/OR MAINTENANCE PROBLEMS IN THE 2012 BASE CASE

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 this proposal. As 

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 

of 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 maintenanceonly sites. 

The emissions reductions in this 

proposal will result in considerable 

progress toward attainment and 

maintenance at the 28 sites that remain 

as nonattainment and/or maintenance 

for the 24-hour 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 previously, these 

emissions reductions are 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 of 

maintenance-only sites by 69 percent in 

2014 compared to the 2012 base case. 

For the 12 sites expected to have 

residual nonattainment/maintenance 

problems in 2014, the predicted ozone 

reductions provide nearly 10 percent of 

the amount needed for these sites to 

attain and/or maintain the ozone 

standard. Thus, our modeling indicates 

that by 2014 the initial phase of summer 

NOX emissions reductions in this 

proposal will lower ozone 

concentrations in the East and help 

bring areas closer to attainment for the 

8-hour ozone NAAQS. 


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113Pope 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. 

114Laden et al., 2006. ‘‘Reduction in Fine 

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173:667–672. 

B. Human Health Benefit Analysis 

To estimate the human health benefits 

of the proposed Transport Rule, we used 

the BenMAP model to quantify the 

changes in 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 on the 

American Cancer Society cohort 

study 113 and the other based on the 

extended Six Cities cohort study.114

Table IX–3 presents the primary 

estimates of reduced incidence of PM2.5

and ozone-related health effects in 2014 

for the proposed and alternative 

remedies. In 2014, we estimate that PMrelated annual benefits of the proposed 

remedy include approximately 14,000 to 

36,000 fewer premature mortalities, 

9,200 fewer cases of chronic bronchitis, 

22,000 fewer non-fatal heart attacks, 

11,000 fewer hospitalizations (for 

respiratory and cardiovascular disease 

combined), 10 million fewer days of 

restricted activity due to respiratory 

illness and approximately 1.8 million 

fewer work-loss days. We also estimate 

substantial health improvements for 

children from fewer cases of upper and 

lower respiratory illness, acute 

bronchitis, and asthma attacks. As 

mentioned earlier, the reduced 

incidences of various effects would be 

greater in 2012 due to the larger 

emissions reductions that occur from 

the baseline. The lower reductions in 

emissions in 2014 result from further 

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 shortterm mortality in 95 U.S. urban communities, 

1987–2000. Journal of the American Medical 

Association. 292 (19): p. 2372–8. 

Laden, F., J. Schwartz, F.E. Speizer, and 

D.W. Dockery. 2006. Reduction in Fine 

Particulate Air Pollution and Mortality. 

American Journal of Respiratory and Critical 

Care Medicine 173:667–672. Estimating the 

Public Health Benefits of Proposed Air 

Pollution Regulations. Washington, DC: The 

National Academies Press. 

Levy JI, Baxter LK, Schwartz J. 2009. 

Uncertainty and variability in health-related 

damages from coal-fired power plants in the 

United States. Risk Anal. doi: 10.1111/ 

j.1539–6924.2009.01227.x [Online 9 Apr 

2009] 

Pope, C.A., III, R.T. Burnett, M.J. Thun, 

E.E. Calle, D. Krewski, K. Ito, and G.D. 

Thurston. 2002. Lung Cancer, 

Cardiopulmonary Mortality, and Long-term 

Exposure to Fine Particulate Air Pollution. 

Journal of the American Medical Association 

287:1132–1141. 

TABLE IX–3—ESTIMATED ANNUAL REDUCTIONS IN INCIDENCE OF HEALTH EFFECTS A

Health effect Proposed remedy 

PM-Related endpoints 

Premature Mortality 

Pope et al. (2002) (age >30) .............................................................................................................................. 14,000 (4,000–25,000) 

Laden et al. (2006) (age >25) ............................................................................................................................ 36,000 (17,000–56,000) 

Infant (< 1 year) .................................................................................................................................................. 59 (¥66–180) 

Chronic Bronchitis .............................................................................................................................................. 9,200 (320–18,000) 

Non-fatal heart attacks (age > 18) ..................................................................................................................... 22,000 (5,800–39,000) 

Hospital admissions—respiratory (all ages) ....................................................................................................... 3,500 (1,400–5,500) 

Hospital admissions—cardiovascular (age > 18) ............................................................................................... 7,500 (5,200–8,900) 

Emergency room visits for asthma (age < 18) .................................................................................................. 14,000 (7,200–21,000) 

Acute bronchitis (age 8–12) ............................................................................................................................... 21,000 (¥4,800–46,000) 

Lower respiratory symptoms (age 7–14) ........................................................................................................... 250,000 (98,000–400,000) 

Upper respiratory symptoms (asthmatics age 9–18) ......................................................................................... 190,000 (36,000–350,000) 

Asthma exacerbation (asthmatics 6–18) ............................................................................................................ 240,000 (8,300–800,000) 

Lost work days (ages 18–65) ............................................................................................................................. 1,800,000 (1,500,000– 

2,000,000) 

Minor restricted-activity days (ages 18–65) ....................................................................................................... 10,000,000 (8,600,000– 

12,000,000) 

Ozone-related endpoints 

Premature mortality 

Bell et al. (2004) (all ages) ................................................................................................................................. 50 (17–84) 

Levy et al. (2005) (all ages) ............................................................................................................................... 230 (160–300) 

Hospital admissions—respiratory causes (ages > 65) ...................................................................................... 390 (¥18–740) 

Hospital admissions—respiratory causes (ages < 2) ........................................................................................ 300 (130–460) 

Emergency room visits for asthma (all ages) .................................................................................................... 230 (¥30–730) 

Minor restricted-activity days (ages 18–65) ....................................................................................................... 300,000 (130,000–480,000) 


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TABLE IX–3—ESTIMATED ANNUAL REDUCTIONS IN INCIDENCE OF HEALTH EFFECTS A—Continued 

Health effect Proposed remedy 

School absence days ......................................................................................................................................... 110,000 (38,000–160,000) 

A Values rounded to two significant figures. Benefits from reducing other criteria pollutants and hazardous air pollutants and ecosystem effects 

are not included here. 

C. Quantified and Monetized Visibility 

Benefits 

Only a subset of the expected 

visibility benefits—those for Class I 

areas—are included in the monetary 

benefits estimates we project for this 

rule. We anticipate improvement in 

visibility in residential areas where 

people live, work and recreate within 

the Transport Rule region for which we 

are currently unable to monetize 

benefits. For the Class I areas we 

estimate annual benefits of $3.4 billion 

beginning in 2014 for visibility 

improvements. Methodological 

limitations prevented us from 

quantifying the visibility benefits of the 

alternate remedies. The value of 

visibility benefits in areas where we 

were unable to monetize benefits could 

also be substantial. 

D. Benefits of Reducing GHG Emissions 

When fully implemented in 2014, the 

proposed Transport Rule would reduce 

emissions of 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–HQ–OAR–2009– 

0472]. 

E. Total Monetized Benefits 

Table IX–4 presents the estimated 

monetary value of reductions in the 

incidence of health and welfare effects. 

These estimates account for increases in 

the value of risk reduction over time. As 

the table indicates, total benefits are 

driven primarily by the reduction in 

premature fatalities each year, which 

account for over 90 percent of total 

benefits. 

Table IX–5 presents the total 

monetized net benefits for 2014. A 

listing of the benefit categories that 

could not be quantified or monetized in 

our benefit estimates are provided in 

Table IX–6. 

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) 

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. 


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E. How do the benefits compare to the 

costs of this proposed rule? 

The estimated annual private costs to 

implement the emission reduction 

requirements of the proposed rule for 

the Transport Rule region are $3.7 

billion in 2012 and $2.8 billion in 2014 

(2006$) for the proposed remedy option, 

$4.2 billion in 2012 and $2.7 billion in 

2014 for the State Budgets/Intrastate 

Trading remedy option, and $4.3 billion 

in 2012 and $3.4 billion in 2014 for the 

direct control remedy option. These 

costs are the annual incremental electric 

generation production costs that are 

expected to occur with the Transport 

Rule. The EPA uses these costs as 

compliance cost estimates in developing 

cost-effectiveness estimates. 

In estimating the net benefits of 

regulation, the appropriate cost measure 

is ‘‘social costs.’’ Social costs represent 

the welfare costs of the rule to society. 

These costs do not consider transfer 

payments (such as taxes) that are simply 

redistributions of wealth. The social 

costs of this rule (thus reflecting the 

proposed remedy option) are estimated 

to be approximately $2.0 billion in 2014 

assuming a 3 percent discount rate. 

These costs become $2.2 billion in 2014, 

if one assumes a 7 percent discount rate. 

Thus, the net benefit (social benefits 

minus social costs) as will be shown in 

Table IX–5 for the proposed remedy 

option is approximately $120 to 292 

billion or $109 to 264 billion (3 percent 

and 7 percent discount rates) in 2014. 

Implementation of the rule is expected 

to provide society with a substantial net 

gain in social welfare based on 

economic efficiency criteria. 

The annualized regional cost of the 

proposed rule, as quantified here, is 

EPA’s best assessment of the cost of 

implementing the proposed option. 

These costs are generated from rigorous 

economic modeling of changes in the 

power sector expected from the 

proposed rule. This type of analysis 

using IPM has undergone peer review 

and been upheld in federal courts. The 

direct cost includes, but is not limited 

to, capital investments in pollution 

controls, operating expenses of the 

pollution controls, investments in new 

generating sources, and additional fuel 

expenditures. The EPA believes that 

these costs reflect, as closely as possible, 

the additional costs of the proposed 

option to industry. The relatively small 

cost associated with monitoring 

emissions, reporting, and recordkeeping 

for affected sources is not included in 

these annualized cost estimates, but 

EPA has done a separate analysis and 

estimated the cost to less than $28 

million (see section XII.B., Paperwork 

Reduction Act). However, there may 

exist certain costs that EPA has not 

quantified in these estimates. These 

costs may include costs of transitioning 

to this rule, such as the costs associated 

with the retirement of smaller or less 

efficient EGUs, employment shifts as 

workers are retrained at the same 

company or re-employed elsewhere in 

the economy, and certain relatively 

small permitting costs associated with 

Title V that new program entrants face. 

An optimization model was employed 

that assumes cost minimization. Costs 

may be understated if the regulated 

community chooses not to minimize its 

compliance costs in the same manner to 

comply with the rules. Although EPA 

has not quantified these costs, the 

Agency believes that they are small 

compared to the quantified costs of the 

program on the power sector. However, 

EPA’s experience and results of 

independent evaluation suggests that 

costs are likely to be lower by some 

degree (see RIA for details). The 

annualized cost estimates presented are 

the best and most accurate based upon 

available information. In a separate 

analysis, EPA estimates the indirect 

costs and impacts of higher electricity 

prices on the entire economy. These 

impacts are summarized in section X of 

this preamble and in the RIA for this 

proposed rule. 

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. 

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. 

aAll 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. cAs 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.’’ eValuation 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. 


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115 In this analysis, we adjust the VSL to account 

for a different currency year (2006$) and to account 

for income growth to 2014. After applying these 

adjustments to the $6.3 million value, the VSL is 

$8.5 million. 

Every benefit-cost analysis examining 

the potential effects of a change in 

environmental protection requirements 

is limited to some extent by data gaps, 

limitations in model capabilities (such 

as geographic coverage), and 

uncertainties in the underlying 

scientific and economic studies used to 

configure the benefit and cost models. 

Gaps in the scientific literature often 

result in the inability to estimate 

quantitative changes in health and 

environmental effects. Gaps in the 

economics literature often result in the 

inability to assign economic values even 

to those health and environmental 

outcomes that can be quantified. While 

uncertainties in the underlying 

scientific and economics literatures 

(that may result in overestimation or 

underestimation of benefits) are 

discussed in detail in the economic 

analyses and its supporting documents 

and references, the key uncertainties 

which have a bearing on the results of 

the benefit-cost analysis of this rule 

include the following: 

• EPA’s inability to quantify 

potentially significant benefit categories; 

• Uncertainties in population growth 

and baseline incidence rates; 

• Uncertainties in projection of 

emissions inventories and air quality 

into the future; 

• Uncertainty in the estimated 

relationships of health and welfare 

effects to changes in pollutant 

concentrations including the shape of 

the C–R function, the size of the effect 

estimates, and the relative toxicity of the 

many components of the PM mixture; 

• Uncertainties in exposure 

estimation; and 

• Uncertainties associated with the 

effect of potential future actions to limit 

emissions. 

Despite these uncertainties, we 

believe the benefit-cost analysis 

provides a reasonable indication of the 

expected economic benefits of the 

rulemaking in future years under a set 

of reasonable assumptions. This 

approach calculates a mean value across 

VSL estimates derived from 26 labor 

market and contingent valuation studies 

published between 1974 and 1991. The 

mean VSL across these studies is $6.3 

million (2000$).115 The benefits 

estimates generated for this rule are 

subject to a number of assumptions and 

uncertainties, which are discussed 

throughout the RIA document. 

As Table IX–4 indicates, total benefits 

are driven primarily by the reduction in 

premature mortalities each year. Some 

key assumptions underlying the primary 

estimate for the premature mortality 

category include the following: 

(1) EPA assumes inhalation of fine 

particles is causally associated with 

premature death at concentrations near 

those experienced by most Americans 

on a daily basis. Plausible biological 

mechanisms for this effect have been 

hypothesized for the endpoints 

included in the primary analysis and 

the weight of the available 

epidemiological evidence supports an 

assumption of causality. 

(2) EPA assumes all fine particles, 

regardless of their chemical 

composition, are equally potent in 

causing premature mortality. This is an 

important assumption, because the 

proportion of certain components in the 

PM mixture produced via precursors 

emitted from EGUs may differ 

significantly from direct PM released 

from automotive engines and other 

industrial sources, but no clear 

scientific grounds exist for supporting 

differential effects estimates by particle 

type. 

(3) We assume that the health impact 

function for fine particles is linear down 

to the lowest air quality levels modeled 

in this analysis. Thus, the estimates 

include health benefits from reducing 

fine particles in areas with varied 

concentrations of PM2.5, including both 

regions that are in attainment with fine 

particle standard and those that do not 

meet the standard down to the lowest 

modeled concentrations. 

The EPA recognizes the difficulties, 

assumptions, and inherent uncertainties 

in the overall enterprise. The analyses 

upon which the Transport Rule is based 

were selected from the peer-reviewed 

scientific literature. We used up-to-date 

assessment tools, and we believe the 

results are highly useful in assessing 

this rule. 

There are a number of health and 

environmental effects that we were 

unable to quantify or monetize. A 

complete benefit-cost analysis of the 

Transport Rule requires consideration of 

all benefits and costs expected to result 

from the rule, not just those benefits and 

costs which could be expressed here in 

dollar terms. A listing of the benefit 

categories that were not quantified or 

monetized in our estimate are provided 

in Table IX–6. 

F. What are the unquantified and 

unmonetized benefits of the Transport 

Rule emissions reductions? 

Important benefits beyond the human 

health and welfare benefits resulting 

from reductions in ambient levels of 

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 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 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 


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concentrations. Biological effects of 

episodes include reduced fish condition 

factor, changes in species composition 

and declines in aquatic species richness 

across multiple taxa, ecosystems and 

regions, as well as fish mortality. Waters 

that are sensitive to acidification tend to 

be located in small watersheds that have 

few alkaline minerals and shallow soils. 

Conversely, watersheds that contain 

alkaline minerals, such as limestone, 

tend to have waters with a high ANC. 

Areas especially sensitive to 

acidification include portions of the 

Northeast (particularly, the Adirondack 

and Catskill Mountains, portions of 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 of plants to other stresses, 

including insect pests and disease 

(Joslin et al., 1992), leading to increased 

mortality of canopy trees. 

Both coniferous and deciduous forests 

throughout the eastern U.S. are 

experiencing gradual losses of base 

cation nutrients from the soil due to 

accelerated leaching for acidifying 

deposition. This change in nutrient 

availability may reduce the quality of 

forest nutrition over the long term. 

Evidence suggests that red spruce and 

sugar maple in some areas in the eastern 

U.S. have experienced declining health 

because of this deposition. For red 

spruce (Picea rubens), dieback or 

decline has been observed across high 

elevation landscapes of the northeastern 

U.S., and to a lesser extent, the 

southeastern U.S., and acidifying 

deposition has been implicated as a 

causal factor (DeHayes et al., 1999). 

This regulatory action will decrease 

acid deposition in the transport region 

and is likely to have positive effects on 

the health and productivity of forest 

systems in the region. 

c. Coastal Ecosystems 

Since 1990, a large amount of research 

has been conducted on the impact of 

nitrogen deposition to coastal waters. 

Nitrogen is often the limiting nutrient in 

coastal ecosystems. Increasing the levels 

of nitrogen in coastal waters can cause 

significant changes to those ecosystems. 

In recent decades, human activities have 

accelerated nitrogen nutrient inputs, 

causing excessive growth of algae and 

leading to degraded water quality and 

associated impairments of estuarine and 

coastal resources. 

Atmospheric deposition of nitrogen is 

a significant source of nitrogen to many 

estuaries. The amount of nitrogen 

entering estuaries due to atmospheric 

deposition varies widely, depending on 

the size and location of the estuarine 

watershed and other sources of nitrogen 

in the watershed. A recent assessment of 

141 estuaries nationwide by the 

National Oceanic and Atmospheric 

Administration (NOAA) concluded that 

19 estuaries (13 percent) suffered from 

moderately high or high levels of 

eutrophication due to excessive inputs 

of both N and phosphorus, and a 

majority of these estuaries are located in 

the coastal area from North Carolina to 

Massachusetts (NOAA, 2007). For 

estuaries in the Mid-Atlantic region, the 

contribution of atmospheric distribution 

to total N loads is estimated to range 

between 10 percent and 58 percent 

(Valigura et al., 2001). 

Eutrophication in estuaries is 

associated with a range of adverse 

ecological effects. The conceptual 

framework developed by NOAA 

emphasizes four main types of 

eutrophication effects—low dissolved 

oxygen (DO), harmful algal blooms 

(HABs), loss of submerged aquatic 

vegetation (SAV), and low water clarity. 

Low DO disrupts aquatic habitats, 

causing stress to fish and shellfish, 

which, in the short-term, can lead to 

episodic fish kills and, in the long-term, 

can damage overall growth in fish and 

shellfish populations. Low DO also 

degrades the aesthetic qualities of 

surface water. In addition to often being 

toxic to fish and shellfish, and leading 

to fish kills and aesthetic impairments 

of estuaries, HABs can, in some 

instances, also be harmful to human 

health. SAV provides critical habitat for 

many aquatic species in estuaries and, 

in some instances, can also protect 

shorelines by reducing wave strength; 

therefore, declines in SAV due to 

nutrient enrichment are an important 

source of concern. Low water clarity is 

the result of accumulations of both algae 

and sediments in estuarine waters. In 

addition to contributing to declines in 

SAV, high levels of turbidity also 

degrade the aesthetic qualities of the 

estuarine environment. 

Estuaries in the eastern United States 

are an important source of food 

production, in particular fish and 

shellfish production. The estuaries are 

capable of supporting large stocks of 

resident commercial species, and they 

serve as the breeding grounds and 

interim habitat for several migratory 

species. 

This rule is anticipated to reduce 

nitrogen deposition in the Transport 

Rule region. Thus, reductions in the 

levels of nitrogen deposition will have 

a positive impact upon current 

eutrophic conditions in estuaries and 

coastal areas in the region. 

d. Mercury Methylation and Deposition 

Mercury is a highly neurotoxic 

contaminant that enters the food web as 

a methylated compound, 

methylmercury (U.S. EPA, 2008d). The 

contaminant is concentrated in higher 

trophic levels, including fish eaten by 

humans. Experimental evidence has 

established that only inconsequential 

amounts of methylmercury can be 

produced in the absence of sulfate. 

Current evidence indicates that in 

watersheds where mercury is present, 

increased 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 

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 regionalscale forest impacts (U.S. EPA, 2006). 

Studies have demonstrated repeatedly 

that ozone concentrations commonly 

observed in polluted areas can have 

substantial impacts on plant function 

(De Steiguer et al., 1990; Pye, 1988). 

Assessing the impact of ground-level 

ozone on forests in the eastern United 

States involves understanding the risks 

to sensitive tree species from ambient 

ozone concentrations and accounting for 

the prevalence of those species within 

the forest. As a way to quantify the risks 

to particular plants from ground-level 


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ozone, scientists have developed ozoneexposure/tree-response functions by 

exposing tree seedlings to different 

ozone levels and measuring reductions 

in growth as ‘‘biomass loss.’’ Typically, 

seedlings are used because they are easy 

to manipulate and measure their growth 

loss from ozone pollution. The 

mechanisms of susceptibility to ozone 

within the leaves of seedlings and 

mature trees are identical, and the 

decreases predicted using the seedlings 

should be related to the decrease in 

overall plant fitness for mature trees, but 

the magnitude of the effect may be 

higher or lower depending on the tree 

species (Chappelka and Samuelson, 

1998). In areas where certain ozonesensitive species dominate the forest 

community, the biomass loss from 

ozone can be significant. Significant 

biomass loss can be defined as a more 

than 2 percent annual biomass loss, 

which would cause long-term ecological 

harm as the short-term negative effects 

on seedlings compound to affect longterm forest health (Heck, 1997). 

Urban ornamentals are an additional 

vegetation category likely to experience 

some degree of negative effects 

associated with exposure to ambient 

ozone levels. Because ozone causes 

visible foliar injury, the aesthetic value 

of ornamentals (such as petunia, 

geranium, and poinsettia) in urban 

landscapes would be reduced (U.S. 

EPA, 2007). Sensitive ornamental 

species would require more frequent 

replacement and/or increased 

maintenance (fertilizer or pesticide 

application) to maintain the desired 

appearance because of exposure to 

ambient ozone (U.S. EPA, 2007). In 

addition, many businesses rely on 

healthy-looking vegetation for their 

livelihoods (e.g., horticulturalists, 

landscapers, Christmas tree growers, 

farmers of leafy crops, etc.) and a variety 

of ornamental species have been listed 

as sensitive to ozone (Abt Associates, 

1995). 

3. Other Health or Welfare Disbenefits of 

the Transport Rule That Have Not Been 

Quantified 

In contrast to the additional benefits 

of the proposed rule discussed above, it 

is also possible that this rule will result 

in disbenefits in some areas of the 

region. Current levels of nitrogen 

deposition in these areas may provide 

passive fertilization for forest and 

terrestrial ecosystems where nutrients 

are a limiting factor and for some 

croplands. The effects of ozone and PM 

on radiative transfer in the atmosphere 

can also lead to effects of uncertain 

magnitude and direction on the 

penetration of ultraviolet light and 

climate. Ground level ozone makes up 

a small percentage of total atmospheric 

ozone (including the stratospheric layer) 

that attenuates penetration of 

ultraviolet-b (UVb) radiation to the 

ground. The EPA’s past evaluation of 

the information indicates that potential 

disbenefits would be small, variable, 

and with too many uncertainties to 

attempt quantification of relatively 

small changes in average ozone levels 

over the course of a year (EPA, 2005a). 

The EPA’s most recent provisional 

assessment of the currently available 

information indicates that potential but 

unquantifiable benefits may also arise 

from ozone-related attenuation of UVb 

radiation (EPA, 2005b). Sulfate and 

nitrate particles also scatter UVb, which 

can decrease exposure of horizontal 

surfaces to UVb, but increase exposure 

of vertical surfaces. In this case as well, 

both the magnitude and direction of the 

effect of reductions in sulfate and nitrate 

particles are too uncertain to quantify 

(EPA, 2004). Ozone is a greenhouse gas, 

and sulfates and nitrates can reduce the 

amount of solar radiation reaching the 

earth, but EPA believes that we are 

unable to quantify any net climaterelated disbenefit or benefit associated 

with the combined ozone and PM 

reductions in this rule. 

Additionally, from analyses of the 

benefits of the Acid Rain Program, EPA 

has seen that substantial health and 

environmental benefits that are likely to 

occur for Canadians because 80 percent 

of the Canadian population lives within 

40 miles of the US-Canada border. 

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. 

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. 


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TABLE IX–6—UNQUANTIFIED AND NON-MONETIZED EFFECTS OF THE TRANSPORT RULE—Continued 

Pollutant/effect Endpoint 

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 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) that are simply 

redistributions of wealth. The social 

costs of this rule for the proposed 

remedy option are estimated to be 

approximately $2.0 billion in 2014 

assuming a 3 percent discount rate. 

These costs become $2.2 billion in 2014 

assuming a 7 percent discount rate. For 

the State Budgets/Intrastate Trading 

remedy, social costs are estimated to be 

approximately $2.5 billion in 2014 

assuming a 3 percent discount rate and 

$2.7 billion in 2014 assuming a 7 

percent discount rate. Finally, for the 

direct control remedy, social costs are 

estimated to be approximately $2.7 

billion in 2014 assuming a 3 percent 

discount rate and $2.9 billion in 2014 

assuming a 7 percent discount rate. 

Overall, the economic impacts of the 

Transport Rule proposal are modest in 

2014, particularly in light of the large 

benefits ($122 to $294 billion annually 

at a 3 percent discount rate and $111 to 

$266 billion annually at a 7 percent 

discount rate) we expect as shown 

earlier in this preamble (see section IX 

for more details). Ultimately, we believe 

the electric power industry will pass 

along most of the costs of the rule to 

consumers, so that the costs of the rule 

will largely fall upon the consumers of 

electricity. For more information on 

electricity price changes that result from 

this proposal, please refer to section 

XII.H (Statement of Energy Effects) later 

in this preamble. 

For this proposed rule, EPA analyzed 

the costs using the Integrated Planning 

Model (IPM). The IPM is a dynamic 

linear programming model that can be 

used to examine the economic impacts 

of air pollution control policies for 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 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 costeffectiveness of energy efficiency 

investments by internalizing 

environmental costs associated with 

these pollutants, EPA is interested in 

considering additional means by which 

energy efficiency can be encouraged 

through this proposed rule. 

1. What is end-use energy efficiency? 

End-use energy efficiency (hereafter, 

‘‘energy efficiency’’) in the context of 

this proposed rule refers to activities 

that reduce the demand for electricity 

from EGUs in affected states. Energy 


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116U.S. EPA. 2004. Guidance on State 

Implementation Plan (SIP) Credits for Emission 

Reductions From Electric-Sector Energy Efficiency 

and Renewable Energy Measures. August. http:// 

www.epa.gov/ttn/oarpg/t1/memoranda/ 

ereseerem_gd.pdf. 

efficiency improvements are pursued 

through the efforts of state agencies, 

independent program administrators 

(e.g. Vermont Energy Investment 

Corporation), electric utilities, energy 

service companies, and other 

commercial entities. Examples of 

common energy efficiency projects 

include re-commissioning of 

commercial buildings, rebates for energy 

efficient appliances, and home energy 

audits. 

2. How does energy efficiency 

contribute to cost-effective reductions of 

air emissions from EGUs? 

EPA recognizes that significant 

opportunity remains for energy 

efficiency improvements in businesses, 

homes, and industry. However, there are 

several informational and market 

barriers that limit investment in costeffective energy efficient practices. 

Several federal programs authorized 

under the Act, including ENERGY 

STAR, are designed to address these 

barriers. 

By reducing the demand for 

electricity energy efficiency reduces the 

need for investments in EGU emissions 

control technologies in order to meet the 

limits of an established state emissions 

budget and can often be implemented at 

a lower cost than traditional control 

technologies. Section III.E in this 

preamble further discusses the 

importance of electricity demand 

reductions as a component of EPA’s 

broader air quality improvement 

strategy for the power sector. 

EPA is available to assist states in 

quantifying the reduction in compliance 

costs of air regulatory programs, 

including the proposed rule, that can be 

realized through effective energy 

efficiency policies and programs. 

3. How does the proposed rule support 

greater investment in energy efficiency? 

By requiring reductions in the 

emissions of 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 costeffectiveness of these investments. Over 

time, this effect is expected to lead to 

increases in energy efficiency 

investments and associated benefits. 

4. How have EPA and states previously 

integrated energy efficiency into air 

regulatory programs? 

Congress, EPA, and states have all 

recognized the value of incorporating 

energy efficiency into air regulatory 

programs. Several allowance-based 

programs—including the Acid Rain 

Program, EPA’s 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 noncapped pollutants from affected EGUs. 

In addition to these allowance-based 

programs, EPA has also established, 

through Guidance,116 a means for 

recognizing the emissions benefits of 

energy efficiency in SIPs and has 

approved their use in individual state 

plans. 

B. Incorporating End-Use Energy 

Efficiency Into the Transport Rule 

As discussed previously, EPA 

believes that increasing end-use energy 

efficiency can be an effective approach 

for reducing compliance costs of the 

proposed rule, as well as for reducing 

EGU emissions that are not the target of 

this rule including mercury, other 

toxics, and carbon dioxide. While EPA 

believes the proposed rule will make 

energy efficiency investments more 

competitive, the Agency is seeking 

comments on additional ways in which 

this rule could further encourage these 

investments. 

1. Options that Could Be Used To 

Incorporate Energy Efficiency Into 

Allowance Based Programs 

As discussed previously, allowancebased programs (such as the proposed 

State Budgets/Limited Trading remedy 

and the alternative State Budgets/ 

Intrastate Trading remedy) of EPA and 

states have supported energy efficiency 

projects through the use of auction 

revenues or the award of allowances. 

EPA considered these options in 

developing this proposal but, for the 

reasons described later, decided not to 

include either option in this proposal. 

2. Why did EPA not propose these 

options? 

The emissions reductions 

requirements of the proposed rule are 

implemented through proposed FIPs. 

This means, among other things, that 

EPA allocates the emission allowances 

directly to individual sources. In 

contrast, when allowance based 

programs are implemented through 

SIPs, states may have significant 

flexibility to determine the methodology 

used to allocate or auction allowances 

in their budgets. Under the proposed 

FIPs, EPA would allocate allowances to 

sources in a manner consistent with the 

methodology used to determine each 

state’s budget. EPA believes this 

approach is appropriate because of the 

link between the allowance allocation 

methodology and the significant 

contribution determinations. EPA 

requests comment on whether EPA has 

authority to and whether it would be 

appropriate for EPA to consider energy 

efficiency considerations in developing 

the allowance allocation methodology. 

In addition, because the emission 

reduction requirements are 

implemented through FIPs, any auction 

of allowances would be conducted by 

EPA. As discussed previously in section 

V.D.5.b, pursuant to the Miscellaneous 

Receipts Act, any revenues from a 

federal auction of allowances must go to 

the U.S. Treasury. This precludes the 

use of proceeds from such an auction to 

reward energy efficiency projects. 

In addition, and as also discussed 

previously in sections III.A and III.B.3, 

EPA anticipates further revisions to the 

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 

reductions requirements identified in 

any such rules could be implemented 

through SIPs. The SIP process could 

give states significant flexibility in 

regards to allocation and auctioning of 

allowances. This flexibility could be 

used by states to support energy 

efficiency projects through the use of 

auction revenues or the award of 

allowances. 

EPA is seeking comment on the 

discussion within this section and the 

use of these and other approaches for 

encouraging energy efficiency within 

the proposed rule. 

XII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under section 3(f)(1) of Executive 

Order 12866 (58 FR 51735, October 4, 


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1993), this action is an ‘‘economically 

significant regulatory action’’ because it 

is likely to have an annual effect on the 

economy of $100 million. Accordingly, 

EPA submitted this action to the Office 

of Management and Budget (OMB) for 

review under EO 12866 and any 

changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. In addition, EPA prepared a 

Regulatory Impact Analysis (RIA) of the 

potential costs and benefits associated 

with this action. 

When estimating the PM2.5- and 

ozone-related human health benefits 

and compliance costs in Table 1 below, 

EPA applied methods and assumptions 

consistent with the state-of-the-science 

for human health impact assessment, 

economics and air quality analysis. EPA 

applied its best professional judgment 

in performing this analysis and believes 

that these estimates provide a 

reasonable indication of the expected 

benefits and costs to the nation of the 

preferred and alternate Transport Rule 

remedies considered by the Agency. The 

Regulatory Impacts Analysis (RIA) 

available in the docket describes in 

detail the empirical basis for EPA’s 

assumptions and characterizes the 

various sources of uncertainties 

affecting the estimates below. 

When characterizing uncertainty in 

the PM-mortality relationship, EPA has 

historically presented a sensitivity 

analysis applying alternate assumed 

thresholds in the PM concentrationresponse relationship. In its synthesis of 

the current state of the PM science, 

EPA’s 2009 Integrated Science 

Assessment (ISA) for Particulate Matter 

concluded that a no-threshold log-linear 

model most adequately portrays the PMmortality concentration-response 

relationship. In the RIA accompanying 

this rule, rather than segmenting out 

impacts predicted to be associated 

levels above and below a ‘bright line’ 

threshold, EPA includes a ‘‘lowestmeasured-level (LML)’’ that illustrates 

the increasing uncertainty that 

characterizes impacts attributed to 

levels of PM2.5 below the LML for each 

study. Figure 5–19 shows the 

distribution of avoided PM mortality 

impacts predicted relative to the 

baseline (i.e. pre-Transport Rule) PM2.5

levels experienced by the population 

receiving the PM2.5 mortality benefit in 

2014 (Figure 5–19). This figure also 

shows the lowest air quality levels 

measured in each of the two primary 

epidemiological studies EPA uses to 

quantify PM-related mortality. This 

information allows readers to determine 

the portion of PM-related mortality 

benefits occurring above or below the 

LML of each study; in general, our 

confidence in the size of the estimated 

reduction PM2.5-related premature 

mortality decreases in areas where 

annual mean PM2.5 levels are further 

below the LML in the two 

epidemiological studies. In this 

analysis, we see that about 80% of the 

estimated benefits accrue among 

populations exposed to annual mean 

PM2.5 levels above 10ug/m3 (the LML in 

the Six Cities study) and 97% of the 

estimated benefits are associated with 

PM levels above 7.5 mg/m3 (the LML in 

the American Cancer Society study used 

for this analysis). While the LML 

analysis provides some insight into the 

level of uncertainty in the estimated PM 

mortality benefits, EPA does not view 

the LML as a threshold and continues to 

quantify PM-related mortality impacts 

using a full range of modeled air quality 

concentrations. 

Table XII.A–1 shows the results of the 

cost and benefits analysis for the 

proposed and alternate remedies. 

TABLE XII.A–1—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF VERSIONS OF THE PROPOSED REMEDY

OPTION IN 2014 a

[Billions of 2006$] 

Description Preferred remedy-State budgets/ 

limited trading Direct control Intrastate trading 

Social costs b

3% discount rate ..................... $2.03 ............................................. $2.68 ............................................. $2.49. 

7% discount rate ..................... $2.23 ............................................. $2.91 ............................................. $2.70. 

Health-related benefits c,d

3% discount rate ..................... $118 to $288 + B .......................... $117 to $286 + B .......................... $113 to $276 + B. 

7% discount rate ..................... $108 to $260 + B .......................... $108 to $262 + B .......................... $104 to $252 + B. 

Net benefits (benefits-costs) 

3% discount rate ..................... $116 to $286 ................................ $115 to $283 ................................ $110 to $273. 

7% discount rate ..................... $105 to $258 ................................ $105 to $259 ................................ $101 to $249. 

Notes: (a) All estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for the year 2014. For 

notational purposes, unquantified benefits are indicated with a ‘‘B’’ to represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits that we 

were able to quantify. A listing of health and welfare effects is provided in RIA Table 1–6. Estimates here are subject to uncertainties discussed 

further in the body of the document. (b) The social costs are the loss of household utility as measured in Hicksian equivalent variation. (c) The 

reduction in premature mortalities account for over 90% of total monetized benefits. Benefit estimates are national. Valuation assumes discounting over the SAB-recommended 20-year segmented lag structure described in Chapter 5. Results reflect 3 percent and 7 percent discount 

rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000; OMB, 2003). The estimate of social benefits 

also includes CO2-related benefits calculated using the social cost of carbon, discussed further in chapter 5. Benefits are shown as a range from 

Pope et al. (2002) to Laden et al. (2006). Monetized benefits do not include unquantified benefits, such as other health effects, reduced sulfur 

deposition or visibility. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle 

type. (d) Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all unquantified benefits and 

disbenefits. Potential benefit categories that have not been quantified and monetized are listed in RIA Table 1–4. 

B. Paperwork Reduction Act 

The information collection 

requirements in the proposed rule have 

been submitted for approval to OMB 

under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. The information 

collection requirements are not 

enforceable until OMB approves them. 

The information collection activities 

in this proposed rule include 

monitoring and the maintenance of 

records. The information generated by 

these activities will be used by EPA to 

ensure that affected facilities comply 

with the emission limits and other 

requirements. Records and reports are 

necessary to enable EPA or states to 

identify affected facilities that may not 

be in compliance with the requirements. 

Based on reported information, EPA 


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will decide which units and what 

records or processes should be 

inspected. The amendments do not 

require any notifications or reports 

beyond those required by the General 

Provisions. The recordkeeping 

requirements require only the specific 

information needed to determine 

compliance. These recordkeeping and 

reporting requirements are specifically 

authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted 

to EPA for which a claim of 

confidentiality is made will be 

safeguarded according to EPA policies 

in 40 CFR part 2, subpart B, 

Confidentiality of Business Information. 

The record-keeping and reporting 

burden to sources resulting from states 

choosing to participate in a regional 

cap-and-trade program is approximately 

$28 million annually. This estimate 

includes the annualized cost of 

installing and operating appropriate 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, the 

Agency will publish a technical 

amendment to 40 CFR part 9 in the 

Federal Register to display the OMB 

control number for the approved 

information collection requirements 

contained in this final rule. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this proposed rule on small entities, 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201. For the 

electric power generation industry, the 

small business size standard is an 

ultimate parent entity defined as having 

a total electric output of 4 million 

megawatt-hours (MW-hr) or less in the 

previous fiscal year. 

(2) A small governmental jurisdiction 

that is a government of a city, county, 

town, school district or special district 

with a population of less than 50,000; 

and 

(3) A small organization that is any 

not-for-profit enterprise which is 

independently owned and operated and 

is not dominant in its field. 

TABLE XII.C–1—POTENTIALLY REGULATED CATEGORIES AND ENTITIES a

Category NAICS 

Code b Examples of potentially regulated entities 

Industry ................................................................. 221112 Fossil fuel-fired electric utility steam generating units. 

Federal Government ............................................ c 221112 Fossil fuel-fired electric utility steam generating units owned by the federal government. 

State/Local ........................................................... c 221112 Fossil fuel-fired electric utility steam generating units owned by municipalities. 

Tribal Government ............................................... 921150 Fossil fuel-fired electric utility steam generating units in Indian Country. 

a Include NAICS categories for source categories that own and operate electric generating units only. 

b North American Industry Classification System. 

cFederal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. 

After considering the economic 

impacts of this proposed rule on small 

entities, EPA is certifying that this 

action will not have a significant 

economic impact on a substantial 

number of small entities. This 

certification is based on the economic 

impact of this proposed action to all 

affected small entities across all 

industries affected. EPA has assessed 

the potential impact of this action on 

small entities and found that 

approximately 550 of the estimated 

4,700 EGUs potentially affected by 

today’s proposal are owned by the 81 

potentially affected small entities 

identified by EPA’s analysis. EPA 

estimates that 30 of the 81 identified 

small entities will have annualized costs 

greater than 1 percent of their revenues, 

and the other 51 are projected to incur 

costs less than 1 percent of revenues. 

While there are costs greater than 1 

percent of revenues for a number of 

small entities, EPA is certifying No 

SISNOSE for several reasons. First, of 

the 30 entities projected to have costs 

greater than 1 percent of revenues, 

around 75 percent of them operate in 

cost of service regions and would 

generally be able to pass any increased 

costs along to rate-payers. This is one of 

the primary reasons given in the 

Regulatory Impact Assessment for the 

Final Clean Air Interstate Rule (EPA– 

452/R–05–002 March 2005) that 

supported EPA’s ‘‘No SISNOSE’’ 

certification in the final CAIR FIP rule 

on April 28, 2006 (71 FR 25366). 

Furthermore, of the approximately 550 

units identified by EPA as being 

potentially owned by small entities, 

approximately two-thirds of the units 

that have higher costs are not expected 

to make operational changes as a result 

of this rule (e.g., install control 

equipment or switch fuels). Their 

increased costs are largely due to 

increased cost of the fuel they would be 

expected to use whether or not they had 

to comply with the proposed rule. 

Further, increased fuel costs are often 

passed through to rate-payers as 

common practice in many areas of the 

United States due to fuel adder 

arrangements instituted by state public 

utility commissions. In addition, EPA’s 

decision to exclude units smaller than 

25 MWe has already significantly 

reduced the burden on small entities. 

Hence, EPA has concluded that there is 

no SISNOSE for this rule. 

For more information on the small 

entity impacts associated with the 

proposed rule, please refer to the 

Economic Impact and Small Business 

Analyses in the public docket. These 

analyses can be found in the Regulatory 

Impact Analysis for this proposed rule. 

Finally, although EPA believes that the 

proposed rule would not have a 

significant economic impact on a 


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substantial number of small entities, 

EPA plans to take steps to conduct 

meetings with industry trade 

associations to discuss regulatory 

options and ensure that the burdens 

imposed on small entities are minimal. 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act of 

1995 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538, requires federal agencies, 

unless otherwise prohibited by law, to 

assess the effects of their regulatory 

actions on state, local, and tribal 

governments and the private sector. 

This rule contains a Federal mandate 

that may result in expenditures of $100 

million or more for state, local, and 

tribal governments, in the aggregate, or 

the private sector in any one year. 

Accordingly, EPA has prepared under 

section 202 of the UMRA a written 

statement which is summarized later. 

Consistent with section 205, EPA has 

identified and considered a reasonable 

number of regulatory alternatives. In 

today’s action, EPA has included three 

remedy options that it considered when 

developing this proposed rule: (1) The 

proposed remedy of State Budgets/ 

Limited Trading, (2) State Budgets/ 

Intrastate Trading, and (3) Direct 

Controls. Moreover, section 205 allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. 

EPA examined the potential economic 

impacts on state and municipalityowned entities associated with this 

rulemaking based on assumptions of 

how the affected states will implement 

control measures to meet their 

emissions. Although EPA does not 

conclude that the requirements of the 

UMRA apply to the Transport Rule, 

these impacts have been calculated to 

provide additional understanding of the 

nature of potential impacts and 

additional information. 

According to EPA’s analysis, of the 84 

government entities considered in this 

analysis and the 482 government 

entities in the Transport Rule region 

that are included in EPA’s modeling, 27 

may experience compliance costs in 

excess of 1 percent of revenues in 2014, 

based on our assumptions of how the 

affected states implement control 

measures to meet their emissions 

budgets as set forth in this rulemaking. 

Government entities projected to 

experience compliance costs in excess 

of 1 percent of revenues have some 

potential for significant impact resulting 

from implementation of the Transport 

Rule. However, as noted previously, it is 

EPA’s position that because these 

government entities can pass on their 

costs of compliance to rate-payers, they 

will not be significantly affected. 

Furthermore, the decision to include 

only units greater than 25 MW in size 

exempts 380 government entities that 

would otherwise be potentially affected 

by the Transport Rule. For more 

information on the impacts estimated 

for this analysis, please refer to the RIA 

for this proposed rule. 

In addition, before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under section 203 of the UMRA, a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. Consistent 

with the intergovernmental consultation 

provisions of section 204 of the UMRA, 

EPA has initiated consultations with 

governmental entities affected by this 

rule. 

The EPA has determined that this rule 

contains a Federal mandate that may 

result in expenditures of $100 million or 

more in 1 year. EPA has determined that 

this rule contains no regulatory 

requirements that might significantly or 

uniquely affect small governments and 

that development of a small government 

plan under section 203 of the Act is not 

required. The costs of compliance will 

be borne predominately by sources in 

the private sector although a small 

number of sources owned by state and 

local governments may also be 

impacted. The requirements in this 

action do not distinguish EGUs based on 

ownership, either for those units that 

are included within the scope of the 

rule or for those units that are exempted 

by the generating capacity cut-off. 

Therefore, this rule is not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

E. Executive Order 13132: Federalism 

This proposed rule does not have 

federalism implications. It will not have 

substantial direct effects on the states, 

on the relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. The proposed 

rule primarily affects private industry, 

and does not impose significant 

economic costs on state or local 

governments. Thus, Executive Order 

13132 does not apply to the proposed 

rule. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and state and local governments, EPA 

will specifically solicit comment on the 

proposed rule from state and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It will not have substantial direct 

effects on tribal governments, on the 

relationship between the Federal 

government and Indian tribes, or on the 

distribution of power and 

responsibilities between the federal 

government and Indian tribes, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to the final rule. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

EPA interprets Executive Order 13045 

(62 FR 19885, April 23, 1997) as 

applying to those regulatory actions that 

concern health or safety risks, such that 

the analysis required under section 

5–501 of the Order has the potential to 

influence the regulation. This action is 

not subject to Executive Order 13045 

because it does not involve decisions on 

environmental health or safety risks that 

may disproportionately affect children. 

The EPA believes that the emissions 

reductions from the strategies in this 

rule will further improve air quality and 

will further improve children’s health. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211 (66 FR 28355, 

May 22, 2001) provides that agencies 

shall prepare and submit to the 

Administrator of the Office of 

Regulatory Affairs, OMB, a Statement of 

Energy Effects for certain actions 

identified as ‘‘significant energy 

actions.’’ Section 4(b) of Executive Order 

13211 defines ‘‘significant energy 


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action’’ as ‘‘any action by an agency 

(normally published in the Federal 

Register) that promulgates or is 

expected to lead to the promulgation of 

a final rule or regulation, including 

notices of inquiry, advance notices of 

proposed rulemaking, and notices of 

proposed rulemaking: (1)(i) That is a 

significant regulatory action under 

Executive Order 12866 or any successor 

order, and (ii) is likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy; or (2) that 

is designated by the Administrator of 

the Office of Information and Regulatory 

Affairs as a significant energy action.’’ 

This proposed rule is a significant 

regulatory action under Executive Order 

12866, and this proposed rule may have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

Under the provisions of this proposed 

rule, EPA projects that approximately 

1.2 GW of coal-fired generation may be 

removed from operation by 2014. In 

practice, however, the units projected to 

be uneconomic to maintain may be 

‘‘mothballed,’’ retired, or kept in service 

to ensure transmission reliability in 

certain parts of the grid. These units are 

predominantly small and infrequently 

used generating units dispersed 

throughout the area affected by the rule. 

Assumptions of higher natural gas 

prices or electricity demand would 

create a greater incentive to keep these 

units operational. The EPA projects that 

the average retail electricity price could 

increase nationally by less than 2.5 

percent in 2012 and 1.5 percent in 2014. 

This is generally less of an increase than 

often occurs with fluctuating fuel prices 

and other market factors. Related to this, 

delivered coal prices increase by about 

7 percent in 2012 and 4 percent in 2014 

as a result of higher demand for lowersulfur coals. The EPA also projects that 

natural gas prices will increase by less 

than 1.7 percent in 2012 and 0.5 percent 

in 2014 and that natural gas use for 

electricity generation will increase by 

less than 73 million mcf by 2014. The 

price increase is also within the range 

we regularly see in delivered natural gas 

prices. Finally, the EPA projects coal 

production for use by the power sector, 

a large component of total coal 

production, will decrease by 3 million 

tons in 2012 and 9 million tons in 2014. 

The EPA does not believe that this rule 

will have any other impacts that exceed 

the significance criteria. 

The EPA believes that a number of 

features of the proposed rulemaking 

serve to reduce its impact on energy 

supply. First, the trading programs in 

State Budgets/Limited Trading provide 

considerable flexibility to the power 

sector and enable industry to comply 

with the emission reduction 

requirements in the most cost-effective 

manner, thus minimizing overall costs 

and the ultimate impact on energy 

supply. Second, the more stringent 

budgets for 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 details 

concerning energy impacts, see the RIA 

for the proposed Transport Rule. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This proposed rule would require all 

sources to meet the applicable 

monitoring requirements of 40 CFR part 

75. Part 75 already incorporates a 

number of voluntary consensus 

standards. 

Consistent with the Agency’s 

Performance Based Measurement 

System (PBMS), Part 75 sets forth 

performance criteria that allow the use 

of alternative methods to the ones set 

forth in Part 75. The PBMS approach is 

intended to be more flexible and costeffective for the regulated community; it 

is also intended to encourage innovation 

in analytical technology and improved 

data quality. At this time, EPA is not 

recommending any revisions to Part 75; 

however, EPA periodically revises the 

test procedures set forth in Part 75. 

When EPA revises the test procedures 

set forth in Part 75 in the future, EPA 

will address the use of any new 

voluntary consensus standards that are 

equivalent. Currently, even if a test 

procedure is not set forth in Part 75, 

EPA is not precluding the use of any 

method, whether it constitutes a 

voluntary consensus standard or not, as 

long as it meets the performance criteria 

specified; however, any alternative 

methods must be approved through the 

petition process under 40 CFR 75.66 

before they are used. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority, lowincome, and Tribal populations in the 

United States. 

1. Consideration of Environmental 

Justice Issues in the Rule Development 

Process 

In the rulemaking process, EPA 

considers whether there are positive or 

negative impacts of the action that 

appear to affect low-income, minority, 

or Tribal communities 

disproportionately, and, regardless of 

whether a disproportionate effect exists, 

whether there is a chance for these 

communities to meaningfully 

participate in the rulemaking process. 

EPA expects that this rule, ‘‘Federal 

Implementation Plans to Reduce 

Interstate Transport of Fine Particulate 

Matter and Ozone,’’ will provide 

significant health and environmental 

benefits to, among others, people with 

asthma, people with heart disease, and 

people living in ozone or fine particle 

(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 on 

air quality changes and the resulting 

health benefits, is presented both in 

section IX of this preamble and in more 

detail in the air quality modeling 

Technical Support Document and the 

Regulatory Impact Analysis (RIA) for 

this rule. These documents can be 

accessed through the rule docket No. 

EPA–HQ–OAR–2009–0491 and from the 

main EPA Web page for the rule http:// 

www.epagov/airtransport. This section 

summarizes the legal basis for this rule, 

and provides background information 

on how this rule fits into the larger 

regulatory strategy for controlling 


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pollution from the power sector. A 

summary of the emissions, air quality, 

and health benefit estimates for this rule 

then follows. 

This rule is replacing an earlier rule 

(the 2005 Clean Air Interstate Rule 

(CAIR)) that was first vacated and then 

remanded to EPA by the U.S. Court of 

Appeals for the District of Columbia 

Circuit. CAIR was vacated by the U.S. 

Court of Appeals for the District of 

Columbia Circuit in July 2008 in a case 

known as North Carolina v. EPA. In 

December 2008, the vacatur was altered 

to a remand based on the likely 

environmental harms of vacating the 

rule and EPA’s stated intent to replace 

the rule promptly. At the time of the 

2008 court ruling, many sources had 

already begun to install and run 

emissions control devices or otherwise 

alter their operations and had 

successfully begun reducing their 

emissions. The court decision has led to 

significant uncertainty among affected 

sources as to what emissions reductions 

will be required and among states and 

communities as to what air quality 

benefits will be achieved. By proposing 

this aggressive replacement rule that 

meets the legal requirements of the CAA 

as interpreted by the Court in the North 

Carolina decision promptly, EPA is both 

maximizing the likelihood that the goals 

of the CAA will be met, and helping 

communities receive the air quality 

benefits they need as quickly as possible 

by minimizing the chance that any 

emissions reductions achieved under 

CAIR would be lost. 

It is important to note that CAA 

section 110(a)(2)(d), which addresses 

transport of criteria pollutants between 

states and is the authority for this rule, 

is only one of many provisions of the 

CAA that provide EPA, states, and local 

governments with authorities to reduce 

exposure to ozone and 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. 

This proposed rule is one of a group 

of regulatory actions that EPA will take 

over the next several years to respond to 

statutory and judicial mandates that will 

reduce exposure to ozone and 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 statutes, we will 

also coordinate these utility-related air 

pollution rules with upcoming 

regulations for the power sector from 

EPA’s Office of Water (OW) and its 

Office of Resource Conservation and 

Recovery (ORCR). The primary actions 

are outlined below and presented in 

more detail in section III.E of this 

preamble. 

Beyond this action and any additional 

efforts undertaken in response to 

comment, other rules that will drive the 

creation of a clean, efficient and 

completely modern power sector 

include: CAA section 112(d) standards 

(one of which is often referred to as a 

Maximum Achievable Control 

Technology (MACT) standard) to reduce 

emissions of air toxics, including 

mercury, and particles from coal- and 

oil-fired power plants; new National 

Ambient Air Quality Standards 

(NAAQS) for ozone, 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; revisions to the New Source 

Performance Standards (NSPS) for 

steam electric generating units; and best 

available retrofit technology (BART) 

requirements and other requirements 

that address visibility and regional haze. 

Within the planning and investment 

horizon for compliance with these rules, 

EPA very likely will be compelled to 

respond to a pending petition to set 

standards for the emissions of 

greenhouse gases (GHGs) from steam 

electric generating units under the New 

Source Performance Standard program. 

Furthermore, as set forth in the recently 

promulgated reinterpretation of the 

Johnson Memo, beginning in 2011 new 

and modified sources of GHG emissions, 

including EGUs, will be subject to 

permits under the Prevention of 

Significant Deterioration program 

requiring them to adopt Best Available 

Control Technology for their GHGs. 

Finally, EPA will pursue energy 

efficiency improvements in the use of 

electricity throughout the economy, 

along with other federal agencies, states 

and other groups, which will contribute 

to additional environmental and public 

health improvements that the Agency 

wants to provide while lowering the 

costs of realizing those improvements. 

Together, these rules and actions will 

have substantial and long-term effects 

on both the U.S. power industry and on 

communities currently breathing dirty 

air. Therefore, we anticipate significant 

interest in many, if not most, of these 

actions from environmental justice 

communities, among many others. EPA 

intends to provide multiple 

opportunities for comment on these 

actions, including during the comment 

process for this rule, and encourages 

environmental justice communities to 

review and comment on them. 

2. Potential Environmental and Public 

Health Impacts to Vulnerable 

Populations 

There are several considerations to 

take into account when assessing the 

effects of this proposed rule on 

minority, low-income, and tribal 

populations. These include: Amount of 

emissions reductions and where they 

take place (including any potential for 

areas of increased emissions); the 

changes in ambient concentrations 

across the affected area; and the health 

benefits expected from the rules. 

Emissions reductions. This proposed 

rule will reduce exposure to 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 mostcontaminated 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 emissions 

reductions to protect maintenance areas 

as well as nonattainment areas reduces 

the likelihood that any areas close to the 

level of the standard will exceed the 

current health-based standards in the 

future. 

Ozone and PM2.5 concentrations in 

both nonattainment and maintenance 

areas identified in this rule are the 

result of both local emissions and longrange transport of pollution. This rule 

requires upwind states to reduce or 

eliminate their significant contribution 

to nonattainment or maintenance 

problems in downwind states. Even 

when the significant contributions of 

upwind states are fully eliminated, 

additional emissions reductions within 

the nonattainment area and/or the 

downwind state will be needed for some 

areas to attain and maintain the 

NAAQS. 

The proposed remedy option for this 

rule would use a limited emissions 

trading mechanism among power plants 

to achieve significant emissions 

reductions in states covered by the rule. 

EPA recognizes that many 

environmental justice communities 

have voiced concerns about emissions 

trading and any resulting potential for 

any emissions increases in any location. 


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This proposed rule uses EPA’s 

authority in CAA § 110(a)(2)(d) to 

require states to eliminate emissions 

from power plants in their state that 

contribute significantly to downwind 

PM2.5 or ozone nonattainment or 

maintenance areas. EPA’s proposed 

mechanism for achieving these 

emissions reductions is to use a tightly 

constrained trading program that 

requires a strict emission ceiling in each 

state while allowing a limited ability to 

shift emissions between facilities or 

states. This approach ensures that 

emissions in each state that significantly 

contribute to downwind nonattainment 

or maintenance areas are controlled, 

while allowing power companies to 

adjust generation based on fluctuations 

in electricity demand, weather, 

availability of low-emitting power 

sources (e.g. temporary shut-down of a 

nuclear power plant for maintenance or 

repairs), or other unanticipated factors 

affecting the interconnected electricity 

grid. 

Any emissions above the state’s 

allocated level must be offset by 

emissions reductions from another state 

in the region below that state’s budget 

or by using extra ‘‘banked’’ allowances 

from earlier years. All sources must 

hold enough allowances to cover their 

emissions; therefore, if they emit more 

than their allocation they must buy 

allowances from another source that 

emitted less than its allocation. 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 emissions rate for each 

facility is reduced but each facility 

could emit more by increasing their 

power output in order to meet 

electricity reliability or other goals. 

Under the intrastate trading option, state 

emissions must stay constant but 

individual facilities within each state 

could increase their emissions as long as 

another facility in the state had 

decreased theirs. By strictly setting state 

budgets to eliminate significant 

contributions to non-attainment and 

maintenance areas that EPA has 

identified in this action, by limiting the 

amount of interstate trading possible 

and by requiring any emissions above 

the level of the allocations to be offset 

by emission decreases elsewhere in the 

region, the proposed remedy options 

reduce ambient concentrations where 

they are most needed. 

EPA’s emissions modeling data 

indicate that nationwide SO2 emissions 

from electric generating units (EGUs) 

will be approximately 6.4 million tons 

(60 percent) lower in 2014 than they 

were in 2005 (which is the year that the 

Clean Air Interstate Rule was finalized). 

Emissions would also decrease when 

compared to the base case (the base case 

estimates of 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 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 

§ 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 located in urban areas. A 

single nonattainment area usually 

contains multiple monitoring sites; 

therefore there are more nonattainment 

sites than nonattainment counties or 

areas. As discussed in detail in section 

IV.D of this preamble, where this 

proposal does not fully quantify all of 

the significant contribution and 

interference with maintenance, EPA 

intends to address these additional 

requirements quickly. To the extent 

possible, EPA will supplement this 

proposed notice with additional 

information so that we can provide 

downwind states with all the certainty 

about upwind emissions reductions 

they need to address their own local 

nonattainment concerns. In addition, as 

stated above, elimination of these 

nonattainment areas may require both 

local and regional emissions reductions 

and this proposed action seeks only to 

address the regional transport 

component. 

As a result of these 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 


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neighboring states and extend east 

through New England, west to Texas, 

south to Florida, and north through the 

Great Lakes states. ‘‘Border’’ states 

immediately outside the transport 

region are also predicted to see 

reductions in air concentrations, even 

though emissions increase in some of 

these states. This is because 

concentrations of fine particles in most 

locations are composed of both local 

emissions and those transported over 

hundreds of miles and emissions 

reductions far away can cause 

significant improvements in local air 

quality. 

The modeling suggests also that there 

may be some small increases in 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. 

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 emissions reductions are 

included in the baseline modeling for 

this proposed Transport Rule and 

therefore not captured as additional 

benefits of this rulemaking. 

As is common when modeling many 

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 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 emissions 

reductions that might be causing 

extremely localized ozone increases are 

certainly causing larger, more 

widespread improvements in ozone 

concentrations in downwind areas. 

Finally, as stated above, it is important 

to note that EPA intends to promulgate 

additional rules over the next few years 

that will further reduce concentrations 

of ozone and PM2.5 and that the federal 

government and the states can and do 

use many different legal authorities to 

limit exposure to ozone. 

Health benefits. This rule reduces 

concentrations of 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 lowincome 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 PMrelated annual benefits of the proposed 

remedy option include approximately 

14,000 to 36,000 fewer premature 

mortalities, 9,200 fewer cases of chronic 

bronchitis, 22,000 fewer non-fatal heart 

attacks, 11,000 fewer hospitalizations 

(for respiratory and cardiovascular 

disease combined), 10 million fewer 

days of restricted activity due to 

respiratory illness and approximately 

1.8 million fewer lost work days. We 

also estimate substantial health 

improvements for children in the form 

of fewer cases of upper and lower 

respiratory illness, acute bronchitis, and 

asthma attacks. 

Ozone health-related benefits are 

expected to occur during the summer 

ozone season (usually ranging from May 

to September in the eastern U.S.). Based 

upon modeling for 2014, annual ozone 

related health benefits are expected to 

include between 50 and 230 fewer 

premature mortalities, 690 fewer 

hospital admissions for respiratory 

illnesses, 230 fewer emergency room 

admissions for asthma, 300,000 fewer 

days with restricted activity levels, and 

110,000 fewer days where children are 

absent from school due to illnesses. 

When adding the PM and ozone-related 

mortalities together, we find that the 

proposed remedy option for this rule 

will yield between 14,000 and 36,000 

fewer premature mortalities. EPA has 

also estimated the benefits of the 

alternate remedies in this proposal 

using a benefit-per-ton estimation 

approach and found they would provide 

similar benefits. 

It should be noted that, as discussed 

in the RIA for this action, there are other 

benefits to the emissions reductions 

discussed here, such as improved 

visibility and, indirectly, reduced 

mercury deposition. Additional benefits 

of reducing emissions of 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 


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sessions to gather information and 

perspectives from stakeholders prior to 

the formal start of the rulemaking 

process. These stakeholders included a 

number of environmental groups who 

requested that EPA consider several 

potential environmental justice issues 

during development of this rule. In 

addition, many environmental justice 

organizations were represented at a 

November 2009 EPA-Health and Human 

Services White House Stakeholder 

Briefing entitled ‘‘The Public Health 

Benefits of Energy Reform’’ in which 

EPA discussed our intention to propose 

this rule in the spring of 2010 and 

participants had the opportunity to 

respond. Finally, EPA notified tribes of 

our intent to propose this rule in the fall 

of 2009 during a regularly scheduled 

meeting to update the National Tribal 

Air Association members of upcoming 

EPA policies and regulations and to 

receive input from them on the effects 

of these efforts in Indian country. These 

were not opportunities for stakeholders 

to comment on the specifics of this 

proposal, as they took place prior to the 

development of this proposal, but they 

provided valuable information that EPA 

used in developing this proposal. 

Upon proposal of this action, the 

Agency will begin an outreach effort 

with environmental justice 

communities, the public, the regulated 

community, state air regulators, and 

others to (1) describe the Transport Rule 

proposal, (2) provide information on the 

2011 CAA Section 112 (d) and other 

upcoming EPA rulemakings affecting 

the power sector, and (3) listen to 

comments from stakeholders. The intent 

will be to inform all stakeholders of the 

industry’s obligations and opportunities 

for the industry to use investments in 

SO2 and NOX reductions to help smooth 

transition to the CAA Section 112(d) 

standards compliance in late 2014. EPA 

intends to continue these efforts over 

time as more information becomes 

available in the development of the 

various rulemakings under development 

for the power sector. 

During the comment period for this 

proposed rule, EPA intends to reach out 

specifically to environmental justice 

communities and organizations to notify 

them of the opportunity to provide 

comments on this rule and to solicit 

their comments on both this rule and 

the upcoming actions described above 

and in section III.E. EPA will hold 

public hearings on this rule; see the 

information at the very beginning of this 

preamble for locations, times and dates. 

Comments can also be submitted in 

writing or electronically by following 

the instructions at the beginning of this 

preamble. 

4. Summary 

EPA believes that the vast majority of 

communities and individuals in areas 

covered by this rule, including 

numerous low-income, minority, and 

Tribal communities in both rural areas 

and inner cities in the East, will see 

significant improvements in air quality 

and resulting improvements in health. 

EPA also recognizes that there is the 

potential for a number of communities 

or individuals outside the region 

covered by this rule to experience 

slightly worse air quality as an indirect 

result of emissions reductions required 

under this proposal. EPA requests 

comment on the impacts of this 

proposed action on low income, 

minority, and Tribal communities. EPA 

will further analyze environmental 

justice issues related to the impacts of 

the rule on those communities based 

both on additional data that may be 

developed and on comments on those 

issues prior to final action on this rule. 

List of Subjects 

40 CFR Part 51 

Administrative practice and 

procedure, Air pollution control, 

Intergovernmental relations, Nitrogen 

oxides, Ozone, Particulate matter, 

Regional haze, Reporting and 

recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 52 

Administrative practice and 

procedure, Air pollution control, 

Intergovernmental relations, Nitrogen 

oxides, Ozone, Particulate matter, 

Regional haze, Reporting and 

recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Parts 72 

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Intergovernmental 

relations, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 78 

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Intergovernmental 

relations, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 97 

Administrative practice and 

procedure, Air pollution control, 

Electric utilities, Nitrogen oxides, 

Reporting and recordkeeping 

requirements, Sulfur dioxide. 

Dated: July 6, 2010. 

Lisa P. Jackson, 

Administrator. 

For the reasons set forth in the 

preamble, parts 51, 52, 72, 78, and 97 

of chapter I of title 40 of the Code of 

Federal Regulations are proposed to be 

amended as follows: 

PART 51—[AMENDED] 

1. The authority citation for Part 51 

continues to read as follows: 

Authority: 23 U.S.C. 101; 42 U.S.C. 7401– 

7671q. 

§ 51.121 [Amended] 

2. Section 51.121 is amended by 

revising paragraph (r)(2) by removing 

the words ‘‘§ 51.123(bb)’’ and adding, in 

their place, the words ‘‘§ 51.123(bb) with 

regard to an ozone season that occurs 

before January 1, 2012’’. 

§ 51.123 [Amended] 

3. Section 51.123 is amended by 

adding a new paragraph (ff) to read as 

follows: 

§ 51.123 Findings and requirements for 

submission of State implementation plan 

revisions relating to emissions of oxides of 

nitrogen pursuant to the Clean Air Interstate 

Rule. 

* * * * * 

(ff) Notwithstanding any provisions of 

paragraphs (a) through (ee) of this 

section, subparts AA through II and 

AAA through III of part 96 of this 

chapter, subparts AA through II and 

AAAA through IIII of part 97 of this 

chapter, and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, the 

Administrator: 

(i) Rescinds the determination in 

paragraph (a) of this section that the 

States identified in paragraph (c) of this 

section must submit a SIP revision with 

respect to the fine particles (PM2.5) 

NAAQS and the 8-hour ozone NAAQS 

meeting the requirements of paragraphs 

(b) through (ee) of this section; and 

(ii) Will not carry out any of the 

functions set forth for the Administrator 

in subparts AA through II and AAAA 

through IIII of part 96 of this chapter, 

subparts AA through II and AAAA 

through IIII of part 97 of this chapter, or 

in any emissions trading program 

provisions in a State’s SIP approved 

under this section; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 


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§ 51.124 [Amended] 

4. Section 51.124 is amended by 

adding a new paragraph (s) to read as 

follows: 

§ 51.124 Findings and requirements for 

submission of State implementation plan 

revisions relating to emissions of sulfur 

dioxide pursuant to the Clean Air Interstate 

Rule. 

* * * * * 

(s) Notwithstanding any provisions of 

paragraphs (a) through (r) of this 

section, subparts AAA through III of 

part 96 of this chapter, subparts AAA 

through III of part 97 of this chapter, 

and any State’s SIP to the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, the 

Administrator: 

(i) Rescinds the determination in 

paragraph (a) of this section that the 

States identified in paragraph (c) of this 

section must submit a SIP revision with 

respect to the fine particles (PM2.5) 

NAAQS meeting the requirements of 

paragraphs (b) through (r) of this 

section; and 

(ii) Will not carry out any of the 

functions set forth for the Administrator 

in subparts AAA through III of part 96 

of this chapter, subparts AAA through 

III of part 97 of this chapter, or in any 

emissions trading program in a State’s 

SIP approved under this section; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

§ 51.125 [Reserved] 

5. Section 51.125 is removed and 

reserved. 

PART 52—[AMENDED] 

6. The authority citation for Part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—General Provisions 

§ 52.35 [Amended] 

7. Section 52.35 is amended by 

adding a new paragraph (f) to read as 

follows: 

§ 52.35 What are the requirements of the 

Federal Implementation Plans (FIPs) for the 

Clean Air Interstate Rule (CAIR) relating to 

emissions of nitrogen oxides? 

* * * * * 

(f) Notwithstanding any provisions of 

paragraphs (a) through (d) of this 

section, subparts AA through II and 

AAAA through IIII of part 97 of this 

chapter, and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

through (d) of this section relating to 

NOX annual or ozone season emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

§ 52.36 [Amended] 

8. Section 52.36 is amended by 

adding a new paragraph (e) to read as 

follows: 

§ 52.36 What are the requirements of the 

Federal Implementation Plans (FIPs) for the 

Clean Air Interstate Rule (CAIR) relating to 

emissions of sulfur dioxide? 

* * * * * 

(e) Notwithstanding any provisions of 

paragraphs (a) through (c) of this 

section, subparts AAA through III of 

part 97 of this chapter and any State’s 

SIP to the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraphs (a) 

through (e) of this section relating to 

SO2 emissions shall not be applicable; 

and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

9. Subpart A is amended by adding 

§§ 52.37 and 52.38 to read as follows: 

§ 52.37 What are the requirements of the 

Federal Implementation Plans (FIPs) under 

the Transport Rule (TR) relating to 

emissions of nitrogen oxides? 

(a)(1) The TR NOX Annual Trading 

Program provisions of part 97 of this 

chapter constitute the TR Federal 

Implementation Plan provisions that 

relate to annual emissions of nitrogen 

oxides (NOX). 

(2) The provisions of subpart AAAAA 

of part 97 of this chapter, regarding the 

TR NOX Annual Trading Program, apply 

to the sources in the following States: 

Alabama, Connecticut, Delaware, 

District of Columbia, Florida, Georgia, 

Illinois, Indiana, Iowa, Kansas, 

Kentucky, Louisiana, Maryland, 

Massachusetts, Michigan, Minnesota, 

Missouri, Nebraska, New Jersey, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Virginia, West Virginia, and 

Wisconsin. 

(3) Following promulgation of an 

approval by the Administrator of a 

State’s SIP as correcting the SIP’s 

deficiency that is the basis for this 

Federal Implementation Plan, the 

provisions of paragraph (a)(2) of this 

section will no longer apply to the 

sources in the State, unless the 

Administrator’s approval of the SIP is 

partial or conditional. 

(4) Notwithstanding the provisions of 

paragraph (a)(3) of this section, if, at the 

time of such approval of the State’s SIP, 

the Administrator has already allocated 

any TR NOX Annual allowances to 

sources in the State for any years, the 

provisions of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation of TR NOX

Annual allowances for those years shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP. 

(b)(1) The TR NOX Ozone Season 

Trading Program provisions of part 97 of 

this chapter constitute the TR Federal 

Implementation Plan provisions that 

relate to emissions of NOX during the 

ozone season, defined as May 1 through 

September 30 of a calendar year. 

(2) The provisions of subpart BBBBB 

of part 97 of this chapter, regarding the 

TR NOX Ozone Season Trading 

Program, apply to sources in each of the 

following States: Alabama, Arkansas, 

Connecticut, Delaware, District of 

Columbia, Florida, Georgia, Illinois, 

Indiana, Kansas, Kentucky, Louisiana, 

Maryland, Michigan, Mississippi, New 

Jersey, New York, North Carolina, Ohio, 

Oklahoma, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, 

and West Virginia. 

(3) Following promulgation of an 

approval by the Administrator of a 

State’s SIP as correcting the SIP’s 

deficiency that is the basis for this 

Federal Implementation Plan, the 

provisions of paragraph (b)(2) of this 

section will no longer apply to sources 

in the State, unless the Administrator’s 

approval of the SIP is partial or 

conditional. 

(4) Notwithstanding the provisions of 

paragraph (b)(3) of this section, if, at the 

time of such approval of the State’s SIP, 

the Administrator has already allocated 

any TR NOX Ozone Season allowances 

to sources in the State for any years, the 

provisions of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation of TR NOX

Ozone Season allowances for those 

years shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP. 


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§ 52.38 What are the requirements of the 

Federal Implementation Plans (FIPs) for the 

Transport Rule (TR) relating to emissions of 

sulfur dioxide? 

(a) The TR SO2 Group 1 Trading 

Program and TR SO2 Group 2 Trading 

Program provisions of part 97 of this 

chapter constitute the TR Federal 

Implementation Plan provisions that 

relate to emissions of sulfur dioxide 

(SO2). 

(b) The provisions of subpart CCCCC 

of part 97 of this chapter, regarding the 

TR SO2 Group 1 Trading Program, apply 

to sources in each of the following 

States: Georgia, Illinois, Indiana, Iowa, 

Kentucky, Michigan, Missouri, New 

York, North Carolina, Ohio, 

Pennsylvania, Tennessee, Virginia, West 

Virginia, and Wisconsin. 

(c) The provisions of subpart DDDDD 

of part 97 of this chapter, regarding the 

TR SO2 Group 2 Trading Program, apply 

to sources in each of the following 

States: Alabama, Connecticut, Delaware, 

District of Columbia, Florida, Kansas, 

Louisiana, Maryland, Massachusetts, 

Minnesota, Nebraska, New Jersey, and 

South Carolina. 

(d) Following promulgation of an 

approval by the Administrator of a 

State’s SIP as correcting the SIP’s 

deficiency that is the basis for this 

Federal Implementation Plan, the 

provisions of paragraph (b) and (c) of 

this section, as applicable, will no 

longer apply to sources in the State, 

unless the Administrator’s approval of 

the SIP is partial or conditional. 

(e) Notwithstanding the provisions of 

paragraph (d) of this section, if, at the 

time of such approval of the State’s SIP, 

the Administrator has already allocated 

any TR SO2 Group 1 allowances or any 

TR SO2 Group 2 allowances (as 

applicable) to sources in the State for 

any years, the provisions of part 97 of 

this chapter authorizing the 

Administrator to complete the 

allocation of TR SO2 Group 1 

allowances or TR SO2 Group 2 

allowances (as applicable) for those 

years shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP. 

Subpart I—Delaware 

10. Section 52.440 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.440 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

11. Section 52.441 is amended by 

designating the introductory text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.441 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart J—District of Columbia 

12. Section 52.484 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.484 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

13. Section 52.485 is amended by 

designating the introductory text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.485 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart P—Indiana 

14. Section 52.789 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.789 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

15. Section 52.790 is amended by 

designating the introductory text as 


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paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.790 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart T—Louisiana 

16. Section 52.984 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.984 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

Subpart X—Michigan 

17. Section 52.1186 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.1186 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

18. Section 52.1187 is amended by 

designating the introductory text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.1187 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart FF—New Jersey 

19. Section 52.1584 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.1584 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

20. Section 52.1185 is amended by 

designating the introductory text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.1585 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart RR—Tennessee 

21. Section 52.2240 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.2240 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX


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allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

22. Section 52.2241 is amended by 

designating the introductory text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.2241 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart SS—Texas 

23. Section 52.2283 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.2283 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II of part 97 

of this chapter to the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraph (a) of 

this section relating to NOX annual 

emissions shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances allocated for 2012 or any 

year thereafter. 

24. Section 52.2284 is amended by 

designating the introductory text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.2284 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart YY—Wisconsin 

25. Section 52.8587 is amended by 

adding a new paragraph (c) to read as 

follows: 

§ 52.8587 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter. 

26. Section 52.8588 is amended by 

designating the introductory text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.8588 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

PART 72—[AMENDED] 

27. The authority citation for Part 72 

is revised to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7411, 7426, 7601, et seq. 

§ 72.2 [Amended] 

28. Section 72.2 is amended by 

removing the definition of ‘‘interested 

person’’. 

PART 78—[AMENDED] 

29. The authority citation for Part 78 

continues to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7411, 7426, 7601, et seq. 

§ 78.1 [Amended] 

30. Section 78.1 is amended by 

adding paragraphs (b)(13) through 

(b)(16) to read as follows: 

§ 78.1 Purpose and scope. 

* * * * * 

(b) * * * 

(13) Under subpart AAAAA of part 97 

of this chapter, 

(i) The decision on allocation of TR 

NOX Annual allowances under 

§ 97.411(a)(2) and (b) of this chapter. 

(ii) The decision on the transfer of TR 

NOX Annual allowances under § 97.423 

of this chapter. 

(iii) The decision on the deduction of 

TR NOX Annual allowances under 

§§ 97.424 and 97.425 of this chapter. 

(iv) The correction of an error in an 

Allowance Management System account 

under § 97.427 of this chapter. 

(iv) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of TR NOX

Annual allowances based on the 

information as adjusted under § 97.428 

of this chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.435 of this chapter. 

(viii) The approval or disapproval of 

a TR opt-in application, the approval or 

disapproval of a request to withdraw, 

the decision on allocation of TR NOX

Annual allowances, and the decision on 

the deduction of TR NOX Annual 

allowances under §§ 97.441 through 

97.444. 

(14) Under subpart BBBBB of part 97 

of this chapter, (i) The decision on 

allocation of TR NOX Ozone Season 


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allowances under § 97.511(a)(2) and (b) 

of this chapter. 

(ii) The decision on the transfer of TR 

NOX Ozone Season allowances under 

§ 97.523 of this chapter. 

(iii) The decision on the deduction of 

TR NOX Ozone Season allowances 

under §§ 97.524 and 97.525 of this 

chapter. 

(iv) The correction of an error in an 

Allowance Management System account 

under § 97.527 of this chapter. 

(iv) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of TR NOX

Ozone Season allowances based on the 

information as adjusted under § 97.528 

of this chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.535 of this chapter. 

(viii) The approval or disapproval of 

a TR opt-in application, the approval or 

disapproval of a request to withdraw, 

the decision on allocation of TR NOX

Ozone Season allowances, and the 

decision on the deduction of TR NOX

Ozone Season allowances under 

§§ 97.541 through 97.544. 

(15) Under subpart CCCCC of part 97 

of this chapter, 

(i) The decision on allocation of TR 

SO2 Group 1 allowances under 

§ 97.611(a)(2) and (b) of this chapter. 

(ii) The decision on the transfer of TR 

SO2 Group 1 allowances under § 97.623 

of this chapter. 

(iii) The decision on the deduction of 

TR SO2 Group 1 allowances under 

§§ 97.624 and 97.625 of this chapter. 

(iv) The correction of an error in an 

Allowance Management System account 

under § 97.627 of this chapter. 

(iv) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of TR SO2 Group 

1 allowances based on the information 

as adjusted under § 97.628 of this 

chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.635 of this chapter. 

(viii) The approval or disapproval of 

a TR opt-in application, the approval or 

disapproval of a request to withdraw, 

the decision on allocation of TR SO2

Group 1 allowances, and the decision 

on the deduction of TR SO2 Group 1 

allowances under §§ 97.641 through 

97.644. 

(16) Under subpart DDDDD of part 97 

of this chapter, 

(i) The decision on allocation of TR 

SO2 Group 2 allowances under 

§ 97.711(a)(2) and (b) of this chapter. 

(ii) The decision on the transfer of TR 

SO2 Group 1 allowances under § 97.723 

of this chapter. 

(iii) The decision on the deduction of 

TR SO2 Group 1 allowances under 

§§ 97.724 and 97.725 of this chapter. 

(iv) The correction of an error in an 

Allowance Management System account 

under § 97.727 of this chapter. 

(iv) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of TR SO2 Group 

1 allowances based on the information 

as adjusted under § 97.728 of this 

chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.735 of this chapter. 

(viii) The approval or disapproval of 

a TR opt-in application, the approval or 

disapproval of a request to withdraw, 

the decision on allocation of TR SO2

Group 2 allowances, and the decision 

on the deduction of TR SO2 Group 2 

allowances under §§ 97.741 through 

97.744. 

* * * * * 

§ 78.2 [Amended] 

31. Section 78.2 is revised to read as 

follows: 

§ 78.2 General. 

(a) Definitions. (1) The terms used in 

this subpart with regard to a decision of 

the Administrator that is appealed 

under this section shall have the 

meaning as set forth in the regulations 

under which the Administrator made 

such decision and as set forth in 

paragraph (a)(2) of this section. 

(2) Interested person means, with 

regard to a decision of the 

Administrator, any person who 

submitted comments, or testified at a 

public hearing, pursuant to an 

opportunity for comment provided by 

the Administrator as part of the process 

of making such decision, who submitted 

objections pursuant to an opportunity 

for objections provided by the 

Administrator as part of the process of 

making such decision, or who submitted 

his or her name to the Administrator to 

be placed on a list of persons interested 

in such decision. The Administrator 

may update the list of interested persons 

from time to time by requesting 

additional written indication of 

continued interest from the persons 

listed and may delete from the list the 

name of any person failing to respond 

as requested. 

(b) Availability of information. The 

availability to the public of information 

provided to, or otherwise obtained by, 

the Administrator under this subpart 

shall be governed by part 2 of this 

chapter. 

(c) Computation of time. (1) In 

computing any period of time 

prescribed or allowed under this part, 

except as otherwise provided, the day of 

the event from which the period begins 

to run shall not be included, and 

Saturdays, Sundays, and federal 

holidays shall be included. When the 

period ends on a Saturday, Sunday, or 

Federal holiday, the stated period shall 

be extended to include the next 

business day. 

(2) Where a document is served by 

first class mail or commercial delivery 

service, but not by overnight or sameday delivery, 5 days shall be added to 

the time prescribed or allowed under 

this part for the filing of a responsive 

document or for otherwise responding. 

§ 78.3 [Amended] 

32. Section 78.3 is amended by: 

a. In paragraphs (a)(1)(iii), (a)(3)(ii), 

(a)(4)(ii), (a)(5)(ii), (a)(6)(ii), (a)(7)(ii), 

(a)(8)(ii), and (a)(9)(ii), adding, after the 

word ‘‘person’’, the words ‘‘with regard 

to the decision’’. 

b. Adding paragraph (a)(10); 

c. In paragraph (b)(3)(i), removing the 

words ‘‘paragraph (a)(1) and (2)’’ and 

adding, in their place, the words 

‘‘paragraph (a)(1), (2), and (10)’’; and 

d. Adding paragraph (d)(11) to read as 

follows: 

§ 78.3 Petition for administrative review 

and request or evidentiary hearing. 

(a) * * * 

(10) The following persons may 

petition for administrative review of a 

decision of the Administrator that is 

made under subparts AAAAA, BBBBB, 

CCCCC, and DDDDD of part 97 of this 

chapter: 

(i) The designated representative for a 

unit or source, or the authorized 

account representative for any 

Allowance Management System 

account, covered by the decision; or 

(ii) Any interested person with regard 

to the decision. 

* * * * * 

(d) * * * 

(11) Any provision or requirement of 

subparts AAAAA, BBBBB, CCCCC, or 

DDDDD of part 97 of this chapter, 

including the standard requirements 

under § 97.406, § 97.506, § 97.606, or 

§ 97.706 of this chapter and any 

emission monitoring or reporting 

requirements. 

§ 78.4 [Amended] 

33. Section 78.4 is amended by: 

a. Revising paragraph (a) by: 

i. Removing the first, second, third, 

fourth, fifth, and last sentences; 


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ii. In the sixth and seventh sentences, 

removing the words ‘‘interest in’’ and 

adding, in their place, the words 

‘‘ownership interest with respect to’’; 

and 

iii. Redesignating the paragraph as 

paragraph (a)(1)(iii); and 

b. Adding paragraphs (a)(1) 

introductory text, (a)(1)(i), (a)(1)(ii) and 

(a)(2) to read as follows: 

§ 78.4 Filings. 

(a)(1) All original filings made under 

this part shall be signed by the person 

making the filing or by an attorney or 

authorized representative, in accordance 

with the following requirements: 

(i) Any filings on behalf of owners 

and operators of a affected unit or 

affected source, TR NOX Annual unit or 

TR NOX Annual source, TR NOX Ozone 

Season unit or TR NOX Ozone Season 

source, TR SO2 Group 1 unit or TR SO2

Group 1 source, TR SO2 Group 2 unit or 

TR SO2 Group 2 source, or a unit for 

which a TR opt-in application is 

submitted and not withdrawn shall be 

signed by the designated representative. 

Any filing on behalf of persons with an 

ownership interest with respect to 

allowances, TR NOX Annual 

allowances, TR NOX Ozone Season 

allowances, TR SO2 Group 1 

allowances, or TR SO2 Group 2 

allowances in a general account shall be 

signed by the authorized account 

representative. 

(ii) Any filings on behalf of owners 

and operators of a NOX Budget unit or 

NOX Budget source shall be signed by 

the NOX authorized account 

representative. Any filing on behalf of 

persons with an ownership interest with 

respect to NOX allowances in a general 

account shall be signed by the NOX

authorized account representative. 

* * * * * 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile number (if any) of the person 

making the filing shall be provided with 

the filing. 

* * * * * 

PART 97—[AMENDED] 

34. The authority citation for part 97 

continues to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7426, 7601, and 7651, et seq. 

35. Part 97 is amended by adding 

subpart AAAAA to read as follows: 

Subpart AAAAA TR NOX Annual Trading 

Program 

Sec. 

97.401 Purpose. 

97.402 Definitions. 

97.403 Measurements, abbreviations, and 

acronyms. 

97.404 Applicability. 

97.405 Retired unit exemption. 

97.406 Standard requirements. 

97.407 Computation of time. 

97.408 Administrative appeal procedures. 

97.409 [Reserved] 

97.410 State NOX Annual trading budgets, 

new-unit set-asides, and variability 

limits. 

97.411 Timing requirements for TR NOX

Annual allowance allocations. 

97.412 TR NOX Annual allowance 

allocations for new units. 

97.413 Authorization of designated 

representative and alternate designated 

representative. 

97.414 Responsibilities of designated 

representative and alternate designated 

representative. 

97.415 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.416 Certificate of representation. 

97.417 Objections concerning designated 

representative and alternate designated 

representative. 

97.418 Delegation by designated 

representative and alternate designated 

representative. 

97.419 [Reserved] 

97.420 Establishment of Allowance 

Management System accounts. 

97.421 Recordation of TR NOX Annual 

allowance allocations. 

97.422 Submission of TR NOX Annual 

allowance transfers. 

97.423 Recordation of TR NOX Annual 

allowance transfers. 

97.424 Compliance with TR NOX Annual 

emissions limitation. 

97.425 Compliance with TR NOX Annual 

assurance provisions. 

97.426 Banking. 

97.427 Account error. 

97.428 Administrator’s action on 

submissions. 

97.429 [Reserved] 

97.430 General monitoring, recordkeeping, 

and reporting requirements. 

97.431 Initial monitoring system 

certification and recertification 

procedures. 

97.432 Monitoring system out-of-control 

periods. 

97.433 Notifications concerning 

monitoring. 

97.434 Recordkeeping and reporting. 

97.435 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

97.440 General requirements for TR NOX

Annual opt-in units. 

97.441 Opt-in process. 

97.442 Withdrawal of TR NOX Annual optin unit from TR NOX Annual Trading 

Program. 

97.443 Change in regulatory status. 

97.444 TR NOX Annual allowance 

allocations to TR NOX Annual opt-in 

units. 

Subpart AAAAA—TR NOX Annual 

Trading Program 

§ 97.401 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) NOX Annual 

Trading Program, under section 110 of 

the Clean Air Act and § 52.37(a) of this 

chapter, as a means of mitigating 

interstate transport of fine particulates 

and nitrogen oxides. 

§ 97.402 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor) of the United 

States Environmental Protection 

Agency, the Administrator’s duly 

authorized representative under this 

subpart. 

Allocate or allocation means, with 

regard to TR NOX Annual allowances, 

the determination by the Administrator 

of the amount of such TR NOX Annual 

allowances to be initially credited to a 

TR NOX Annual source or a new unit 

set-aside. 

Allowable NOX emission rate means, 

with regard to a unit, the NOX emission 

rate limit that is applicable to the unit 

and covers the longest averaging period 

not exceeding one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR NOX

Annual allowances under the TR NOX

Annual Trading Program. Such 

allowances are allocated, held, 

deducted, or transferred only as whole 

allowances. The Allowance 

Management System is a component of 

the CAMD Business System, which is 

the system used by the Administrator to 

handle TR NOX Annual allowances and 

data related to NOX emissions. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

NOX Annual allowances. 

Allowance transfer deadline means, 

for a control period, midnight of March 

1 (if it is a business day), or midnight 

of the first business day thereafter (if 

March 1 is not a business day), 

immediately after such control period 

and is the deadline by which a TR NOX

Annual allowance transfer must be 

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Annual source’s compliance account in 

order to be available for use in 

complying with the source’s TR NOX

Annual emissions limitation for such 

control period in accordance with 

§ 97.424. 

Alternate designated representative 

means, for a TR NOX Annual source and 

each TR NOX Annual unit at the source, 

the natural person who is authorized by 

the owners and operators of the source 

and all such units at the source, in 

accordance with this subpart, to act on 

behalf of the designated representative 

in matters pertaining to the TR NOX

Annual Trading Program. If the TR NOX

Annual source is also subject to the 

Acid Rain Program, TR NOX Ozone 

Season Trading Program, TR SO2 Group 

1 Trading Program, or TR SO2 Group 2 

Trading Program, then this natural 

person shall be the same natural person 

as the alternate designated 

representative as defined in § 72.2 of 

this chapter, § 97.502, § 97.602, or 

§ 97.702 respectively. 

Authorized account representative 

means, with regard to a general account, 

the natural person who is authorized, in 

accordance with this subpart, to transfer 

and otherwise dispose of TR NOX

Annual allowances held in the general 

account and, with regard to a TR NOX

Annual source’s compliance account, 

the designated representative of the 

source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 

(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil-or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

Certifying official means a natural 

person who is: 

(1) For a corporation, a president, 

secretary, treasurer, or vice-president or 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy or 

decision-making functions for the 

corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Coal-fired means combusting any 

amount of coal or coal-derived fuel, 

alone or in combination with any 

amount of any other fuel, during 1990 

or any year thereafter. 

Cogeneration system means an 

integrated group, at a source, of 

equipment (including a boiler, or 

combustion turbine, and a steam turbine 

generator) designed to produce useful 

thermal energy for industrial, 

commercial, heating, or cooling 

purposes and electricity through the 

sequential use of energy. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine— 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing during the later of 1990 

or the 12-month period starting on the 

date that the unit first produces 

electricity and during each calendar 

year after the later of 1990 or the 

calendar year in which the unit first 

produces electricity— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle unit, useful 

power not less than 45 percent of total 

energy input; 

(3) Provided that the total energy 

input under paragraphs (2)(i)(B) and 

(2)(ii) of this definition shall equal the 

unit’s total energy input from all fuel, 

except biomass if the unit is a boiler; 

and 

(4) Provided that, if a topping-cycle 

unit is operated as part of a cogeneration 

system during a calendar year and the 

cogeneration system meets on a systemwide basis the requirement in paragraph 

(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such 

requirement during that calendar year. 

Combustion turbine means an 

enclosed device comprising: 

(1) If the device is simple cycle, a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the device is combined cycle, 

the equipment described in paragraph 

(1) of this definition and any associated 

duct burner, heat recovery steam 

generator, and steam turbine. 

Commence commercial operation 

means, with regard to a unit: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 97.405. 

(i) For a unit that is a TR NOX Annual 

unit under § 97.404 on the later of 

November 15, 1990 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit that is a TR NOX

Annual unit under § 97.404 on the later 

of November 15, 1990 or the date the 

unit commences commercial operation 

as defined in the introductory text of 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source, such date shall remain the 

replaced unit’s date of commencement 

of commercial operation, and the 


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replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 97.405, for a unit that is not a TR 

NOX Annual unit under § 97.404 on the 

later of November 15, 1990 or the date 

the unit commences commercial 

operation as defined in introductory text 

of paragraph (1) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a TR NOX

Annual unit under § 97.404. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that subsequently undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source), 

such date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that is subsequently replaced by a 

unit at the same source, such date shall 

remain the replaced unit’s date of 

commencement of commercial 

operation, and the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

Commence operation means, with 

regard to a unit: 

(1) To have begun any mechanical, 

chemical, or electronic process, 

including start-up of the unit’s 

combustion chamber. 

(2) For a unit that undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source) 

after the date the unit commences 

operation as defined in paragraph (1) of 

this definition, such date shall remain 

the date of commencement of operation 

of the unit, which shall continue to be 

treated as the same unit. 

(3) For a unit that is replaced by a unit 

at the same source after the date the unit 

commences operation as defined in 

paragraph (1) of this definition, such 

date shall remain the replaced unit’s 

date of commencement of operation, 

and the replacement unit shall be 

treated as a separate unit with a separate 

date for commencement of operation as 

defined in paragraph (1), (2), or (3) of 

this definition as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR NOX Annual 

source under this subpart, in which any 

TR NOX Annual allowance allocations 

for the TR NOX Annual units at the 

source are recorded and in which are 

held any TR NOX Annual allowances 

available for use for a control period in 

complying with the source’s TR NOX

Annual emissions limitation in 

accordance with § 97.424 and the TR 

NOX Annual assurance provisions in 

accordance with § 97.425. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of NOX emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.430 

through 97.435. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A NOX concentration monitoring 

system, consisting of a NOX pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of NOX

emissions, in parts per million (ppm); 

(3) A NOX emission rate (or NOXdiluent) monitoring system, consisting 

of a NOX pollutant concentration 

monitor, a diluent gas (CO2 or O2) 

monitor, and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of NOX concentration, in parts 

per million (ppm), diluent gas 

concentration, in percent CO2 or O2, and 

NOX emission rate, in pounds per 

million British thermal units (lb/ 

mmBtu); 

(4) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(5) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(6) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting January 1 of a calendar year, 

except as provided in § 97.406(c)(3), and 

ending on December 31 of the same 

year, inclusive. 

Designated representative means, for 

a TR NOX Annual source and each TR 

NOX Annual unit at the source, the 

natural person who is authorized by the 

owners and operators of the source and 

all such units at the source, in 

accordance with this subpart, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

TR NOX Annual Trading Program. If the 

TR NOX Annual source is also subject 

to the Acid Rain Program, TR NOX

Ozone Season Trading Program, TR SO2

Group 1 Trading Program, or TR SO2

Group 2 Trading Program, then this 

natural person shall be the same natural 

person as the designated representative, 

as defined in § 72.2 of this chapter, 

§ 97.502, § 97.602, or § 97.702 

respectively. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart. 

Excess emissions means any ton of 

NOX emitted from the TR NOX Annual 

units at a TR NOX Annual source during 

a control period that exceeds the TR 

NOX Annual emissions limitation for 

the source. 

Fossil fuel means— 

(1) Natural gas, petroleum, coal, or 

any form of solid, liquid, or gaseous fuel 

derived from such material; or 

(2) For purposes of applying 

§§ 97.404(b)(2)(i)(B), 97.404(b)(2)(ii)(B), 

and 97.404(b)(2)(iii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 1990 or any calendar year 

thereafter. 

Fuel oil means any petroleum-based 

fuel (including diesel fuel or petroleum 

derivatives such as oil tar) and any 


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recycled or blended petroleum products 

or petroleum by-products used as a fuel 

whether in a liquid, solid, or gaseous 

state. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a unit, electricity made 

available for use, including any such 

electricity used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Heat input means, with regard to a 

unit for a specified period of time, the 

product (in mmBtu/time) of the gross 

calorific value of the fuel (in mmBtu/lb) 

multiplied by the fuel feed rate into a 

combustion device (in lb of fuel/time), 

as measured, recorded, and reported to 

the Administrator by the designated 

representative and as modified by the 

Administrator in accordance with this 

subpart and excluding the heat derived 

from preheated combustion air, 

recirculated flue gases, or exhaust. 

Heat input rate means the amount of 

heat input (in mmBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means 

the maximum amount of fuel per hour 

(in Btu/hr) that a unit is capable of 

combusting on a steady state basis as of 

the initial installation of the unit as 

specified by the manufacturer of the 

unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as of such 

installation as specified by the 

manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as of such completion as 

specified by the person conducting the 

physical change. 

Newly affected TR NOX Annual unit 

means a unit that was not a TR NOX

Annual unit when it began operating 

but that thereafter becomes a TR NOX

Annual unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means any person who 

operates, controls, or supervises a TR 

NOX Annual unit or a TR NOX Annual 

source and shall include, but not be 

limited to, any holding company, utility 

system, or plant manager of such a unit 

or source. 

Owner means, with regard to a TR 

NOX Annual source or a TR NOX

Annual unit at a source respectively, 

any of the following persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR NOX

Annual unit at the source or the TR NOX

Annual unit; 

(2) Any holder of a leasehold interest 

in a TR NOX Annual unit at the source 

or the TR NOX Annual unit, provided 

that, unless expressly provided for in a 

leasehold agreement, ‘‘owner’’ shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such TR 

NOX Annual unit; 

(3) Any purchaser of power from a TR 

NOX Annual unit at the source or the TR 

NOX Annual unit under a life-of-theunit, firm power contractual 

arrangement; 

(4) Provided that, for purposes of 

applying the TR NOX Annual assurance 

provisions in §§ 97.406(c)(2) and 97.425, 

if one or more owners (as defined in 

paragraphs (1) through (3) of this 

definition) of one or more TR NOX

Annual units in a State are wholly 

owned by another, common owner, all 

such owners shall be treated collectively 

as a single owner in the State. 

Owner’s assurance level means: 

(1) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.406(c)(2)(iii)(A) and not as 

described in § 97.406(c)(2)(iii)(B), the 

owner’s share of the State NOX Annual 

trading budget with the one-year 

variability limit for the State for such 

control period; or 

(2) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.406(c)(2)(iii)(B), the owner’s share 

of the State NOX Annual trading budget 

with the three-year variability limit for 

the State for such control period. 

Owner’s share means: 

(1) With regard to a total amount of 

NOX emissions from all TR NOX Annual 

units in a State during a control period, 

the total tonnage of NOX emissions 

during such control period from all of 

the owner’s TR NOX Annual units in the 

State; 

(2) With regard to a State NOX Annual 

trading budget with a one-year 

variability limit for a control period, the 

amount (rounded to the nearest 

allowance) equal to the total amount of 

TR NOX Annual allowances allocated 

for such control period to all of the 

owner’s TR NOX Annual units in the 

State, multiplied by the sum of the State 

NOX Annual trading budget under 

§ 97.410(a) and the State’s one-year 

variability limit under § 97.410(b) and 

divided by such State NOX Annual 

trading budget; 

(3) With regard to a State NOX Annual 

trading budget with a three-year 

variability limit for a control period, the 

amount (rounded to the nearest 

allowance) equal to the total amount of 

TR NOX Annual allowances allocated 

for such control period to all of the 

owner’s TR NOX Annual units in the 

State, multiplied by the sum of the State 

NOX Annual trading budget under 

§ 97.410(a) and the State’s three-year 

variability limit under § 97.410(b) and 

divided by such State NOX Annual 

trading budget; 

(4) Provided that, in the case of a unit 

with more than one owner, the amount 

of tonnage of NOX emissions and of TR 

NOX Annual allowances allocated for a 

control period, with regard to such unit, 

used in determining each owner’s share 


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shall be the amount (rounded to the 

nearest ton and the nearest allowance) 

equal to the unit’s NOX emissions and 

allocation of such allowances, 

respectively, for such control period 

multiplied by the percentage of 

ownership in the unit that the owner’s 

legal, equitable, leasehold, or 

contractual reservation or entitlement in 

the unit comprises as of December 31 of 

such control period; 

(5) Provided that, where two or more 

units emit through a common stack that 

is the monitoring location from which 

NOX mass emissions are reported for a 

control period for a year, the amount of 

tonnage of each unit’s NOX emissions 

used in determining each owner’s share 

for such control period shall be: 

(i) The amount (rounded to the 

nearest ton) of NOX emissions reported 

at the common stack multiplied by the 

quotient of such unit’s heat input for 

such control period divided by the total 

heat input reported from the common 

stack for such control period; 

(ii) An amount determined in 

accordance with a methodology that the 

Administrator determines is consistent 

with the purposes of this definition and 

whose adverse effect (if any) the 

Administrator determines will be de 

minimis; or 

(iii) An amount approved by the 

Administrator in response to a petition 

for an alternative requirement submitted 

in accordance with § 97.435; and 

(6) Provided that, in the case of a unit 

that operates during, but is allocated no 

TR NOX Annual allowances for, a 

control period, the unit shall be treated, 

solely for purposes of this definition, as 

being allocated an amount (rounded to 

the nearest allowance) of TR NOX

Annual allowances for such control 

period equal to the lesser of— 

(i) The unit’s allowable NOX emission 

rate (in lb per MWe) applicable to such 

control period, multiplied by a capacity 

factor of 0.84 (if the unit is a coal-fired 

boiler), 0.15 (if the unit is a simple 

combustion turbine), or 0.66 (if the unit 

is a combined cycle turbine), multiplied 

by the unit’s maximum hourly load as 

reported in accordance with this subpart 

and by 8,760 hours/control period, and 

divided by 2,000 lb/ton; or 

(ii) For a unit listed in appendix A to 

this subpart, the sum of the unit’s NOX

emissions in the control period in the 

last three years during which the unit 

operated during the control period, 

divided by three. 

Permanently retired means, with 

regard to a unit, a unit that is 

unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Potential electrical output capacity 

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/ 

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR NOX Annual 

allowances, the moving of TR NOX

Annual allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) For a topping-cycle unit, the use 

of reject heat from electricity production 

in a useful thermal energy application 

or process; or 

(2) For a bottoming-cycle unit, the use 

of reject heat from useful thermal energy 

application or process in electricity 

production. 

Serial number means, for a TR NOX

Annual allowance, the unique 

identification number assigned to each 

TR NOX Annual allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source,’’ ‘‘stationary 

source,’’ or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States or the 

District of Columbia that is subject to 

the TR NOX Annual Trading Program 

pursuant to § 52.37(a) of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline shall 

be determined by the date of dispatch, 

transmission, or mailing and not the 

date of receipt. 

Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means total energy 

of all forms supplied to a unit, 

excluding energy produced by the unit. 

Each form of energy supplied shall be 

measured by the lower heating value of 

that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55(W + 9H) 

Where: 

LHV = lower heating value of the form of 

energy in Btu/lb, 

HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means the sum of 

useful power and useful thermal energy 

produced by the unit. 

TR NOX Annual allowance means a 

limited authorization issued and 

allocated by the Administrator under 

this subpart to emit one ton of NOX

during a control period of the specified 

calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the TR 

NOX Annual Program. 

TR NOX Annual allowance deduction 

or deduct TR NOX Annual allowances 

means the permanent withdrawal of TR 

NOX Annual allowances by the 

Administrator from a compliance 

account, e.g., in order to account for 

compliance with the TR NOX Annual 

emissions limitation or assurance 

provisions. 

TR NOX Annual allowances held or 

hold TR NOX Annual allowances means 

the TR NOX Annual allowances treated 


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as included in an Allowance 

Management System account as of a 

specified point in time because at that 

time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR NOX Annual allowance 

transfer in accordance with this subpart; 

and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR NOX Annual 

allowance transfer in accordance with 

this subpart. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with this subpart and 

52.37(a) of this chapter, as a means of 

mitigating interstate transport of fine 

particulates and NOX. 

TR NOX Annual emissions limitation 

means, for a TR NOX Annual source, the 

tonnage of NOX emissions authorized in 

a control period by the TR NOX Annual 

allowances available for deduction for 

the source under § 97.424(a) for such 

control period. 

TR NOX Annual source means a 

source that includes one or more TR 

NOX Annual units. 

TR NOX Annual unit means a unit 

that is subject to the TR NOX Annual 

Trading Program under § 97.404. 

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established by the 

Administrator in accordance with 

subpart BBBBB of this part and 52.37(b) 

of this chapter, as a means of mitigating 

interstate transport of ozone and NOX. 

TR SO2 Group 1 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with subpart CCCCC of this 

part and 52.38(b) of this chapter, as a 

means of mitigating interstate transport 

of fine particulates and SO2. 

TR SO2 Group 2 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with subpart DDDDD of this 

part and 52.38(c) of this chapter, as a 

means of mitigating interstate transport 

of fine particulates and SO2. 

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired 

combustion turbine, or other stationary, 

fossil-fuel-fired combustion device. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means electricity or 

mechanical energy that a unit makes 

available for use, excluding any such 

energy used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.403 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.404 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State shall 

be TR NOX Annual units, and any 

source that includes one or more such 

units shall be a TR NOX Annual source, 

subject to the requirements of this 

subpart: Any stationary, fossil-fuel-fired 

boiler or stationary, fossil-fuel-fired 

combustion turbine serving at any time, 

since the later of November 15, 1990 or 

the start-up of the unit’s combustion 

chamber, a generator with nameplate 

capacity of more than 25 MWe 

producing electricity for sale. 

(2) If a stationary boiler or stationary 

combustion turbine that, under 

paragraph (a)(1) of this section, is not a 

TR NOX Annual unit begins to combust 

fossil fuel or to serve a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale, the 

unit shall become a TR NOX Annual 

unit as provided in paragraph (a)(1) of 

this section on the first date on which 

it both combusts fossil fuel and serves 

such generator. 

(b) Any unit in a State that otherwise 

is a TR NOX Annual unit under 

paragraph (a) of this section and that 

meets the requirements set forth in 

paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) 

of this section shall not be a TR NOX

Annual unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

during the later of 1990 or the 12-month 

period starting on the date the unit first 

produces electricity and continuing to 

qualify as a cogeneration unit; and 

(B) Not serving at any time, since the 

later of November 15, 1990 or the startup of the unit’s combustion chamber, a 

generator with nameplate capacity of 

more than 25 MWe supplying in any 

calendar year more than one-third of the 

unit’s potential electric output capacity 

or 219,000 MWh, whichever is greater, 

to any utility power distribution system 

for sale. 

(ii) If a unit qualifies as a cogeneration 

unit during the later of 1990 or the 12- 

month period starting on the date the 

unit first produces electricity and meets 

the requirements of paragraphs (b)(1)(i) 

of this section for at least one calendar 

year, but subsequently no longer meets 

such qualification and requirements, the 

unit shall become a TR NOX Annual 

unit starting on the earlier of January 1 

after the first calendar year during 

which the unit first no longer qualifies 

as a cogeneration unit or January 1 after 

the first calendar year during which the 

unit no longer meets the requirements of 

paragraph (b)(1)(i)(B) of this section. 

(2)(i) Any unit commencing operation 

before January 1, 1985: 

(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average annual fuel 

consumption of fossil fuel for 1985– 

1987 less than 20 percent (on a Btu 

basis) and an average annual fuel 

consumption of fossil fuel for any 3 

consecutive calendar years after 1990 

less than 20 percent (on a Btu basis). 

(ii) Any unit commencing operation 

on or after January 1, 1985: 


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(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average annual fuel 

consumption of fossil fuel for the first 

3 calendar years of operation less than 

20 percent (on a Btu basis) and an 

average annual fuel consumption of 

fossil fuel for any 3 consecutive 

calendar years after 1990 less than 20 

percent (on a Btu basis). 

(iii) If a unit qualifies as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and meets the requirements 

of paragraph (b)(2)(i) or (ii) of this 

section for at least 3 consecutive 

calendar years, but subsequently no 

longer meets such qualification and 

requirements, the unit shall become a 

TR NOX Annual unit starting on the 

earlier of January 1 after the first 

calendar year during which the unit first 

no longer qualifies as a solid waste 

incineration unit or January 1 after the 

first 3 consecutive calendar years after 

1990 for which the unit has an average 

annual fuel consumption of fossil fuel of 

20 percent or more. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 

may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR NOX

Annual Trading Program to the unit or 

other equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 

equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the petition shall 

include the following certification 

statement, signed by the certifying 

official: ‘‘I am authorized to make this 

submission on behalf of the owners and 

operators of the unit or other equipment 

for which the submission is made. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) Response. The Administrator will 

issue a written response to the petition 

and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR NOX

Annual Trading Program to the unit or 

other equipment shall be binding on any 

permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.405 Retired unit exemption. 

(a)(1) Any TR NOX Annual unit that 

is permanently retired and is not a TR 

NOX Annual opt-in unit shall be exempt 

from § 97.406(b) and (c)(1), § 97.424, 

and §§ 97.430 through 97.435. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR NOX

Annual unit is permanently retired. 

Within 30 days of the unit’s permanent 

retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any NOX, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

NOX Annual Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 

§ 97.406 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.413 through 97.418. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each TR 

NOX Annual source and each TR NOX

Annual unit at the source shall comply 

with the monitoring, reporting, and 

recordkeeping requirements of §§ 97.430 

through 97.435. 

(2) The emissions data determined in 

accordance with §§ 97.430 through 

97.435 shall be used to calculate 

allocations of TR NOX Annual 

allowances under §§ 97.411(a)(2) and (b) 

and 97.412 and to determine 

compliance with the TR NOX Annual 

emissions limitation and assurance 

provisions under paragraph (c) of this 

section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.430 through 97.435 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) NOX emissions requirements. (1) 

TR NOX Annual emissions limitation. (i) 

As of the allowance transfer deadline for 

a control period, the owners and 

operators of each TR NOX Annual 

source and each TR NOX Annual unit at 

the source shall hold, in the source’s 

compliance account, TR NOX Annual 

allowances available for deduction for 

such control period under § 97.424(a) in 

an amount not less than the tons of total 

NOX emissions for such control period 

from all TR NOX Annual units at the 

source. 

(ii) If a TR NOX Annual source emits 

NOX during any control period in excess 

of the TR NOX Annual emissions 

limitation set forth in paragraph (c)(1)(i) 

of this section, then: 


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(A) The owners and operators of the 

source and each TR NOX Annual unit at 

the source shall hold the TR NOX

Annual allowances required for 

deduction under § 97.424(d) and pay 

any fine, penalty, or assessment or 

comply with any other remedy imposed, 

for the same violations, under the Clean 

Air Act; and 

(B) Each ton of such excess emissions 

and each day of such control period 

shall constitute a separate violation of 

this subpart and the Clean Air Act. 

(2) TR NOX Annual assurance 

provisions. (i) If the total amount of 

NOX emissions from all TR NOX Annual 

units in a State during a control period 

in 2014 or any year thereafter exceeds 

the State assurance level as described in 

paragraph (c)(2)(iii) of this section, then 

each owner whose share of such NOX

emissions during such control period 

exceeds the owner’s assurance level for 

the State and such control period shall 

hold, in a compliance account 

designated by the owner in accordance 

with § 97.425(b)(4)(ii), TR NOX Annual 

allowances available for deduction for 

such control period under § 97.425(a) in 

an amount equal to the product, as 

determined by the Administrator in 

accordance with § 97.425(b), of 

multiplying— 

(A) The quotient (rounded to the 

nearest whole number) of the amount by 

which the owner’s share of such NOX

emissions exceeds the owner’s 

assurance level divided by the sum of 

the amounts, determined for all such 

owners, by which each owner’s share of 

such NOX emissions exceeds that 

owner’s assurance level; and 

(B) The amount by which total NOX

emissions for all TR NOX Annual units 

in the State for such control period 

exceed the State assurance level as 

determined in accordance with 

paragraph (c)(2)(iii) of this section. 

(ii) The owner shall hold the TR NOX

Annual allowances required under 

paragraph (c)(2)(i) of this section, as of 

midnight of November 1 (if it is a 

business day), or midnight of the first 

business day thereafter (if November 1 

is not a business day), immediately after 

such control period. 

(iii) The total amount of NOX

emissions from all TR NOX Annual 

units in a State during a control period 

in 2014 or any year thereafter exceeds 

the State assurance level: 

(A) If such total amount of NOX

emissions exceeds the sum, for such 

control period, of the State NOX Annual 

trading budget and the State’s one-year 

variability limit under § 97.410(b); or 

(B) If, with regard to a control period 

in 2016 or any year thereafter, the sum, 

divided by three, of such total amount 

of NOX emissions and the total amounts 

of NOX emissions from all TR NOX

Annual units in the State during the 

control periods in the immediately 

preceding two years exceeds the sum, 

for such control period, of the State NOX

Annual trading budget and the State’s 

three-year variability limit under 

§ 97.410(b); 

(C) Provided that the amount by 

which such total amount of NOX

emissions exceeds the State assurance 

level shall be the greater of the amounts 

of the exceedance calculated under 

paragraph (c)(2)(iii)(A) of this section 

and under paragraph (c)(2)(iii)(B) of this 

section. 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if the 

total amount of NOX emissions from all 

TR NOX Annual units in a State during 

a control period exceeds the State 

assurance level or if an owner’s share of 

total NOX emissions from the TR NOX

Annual units in a State during a control 

period exceeds the owner’s assurance 

level. 

(v) To the extent an owner fails to 

hold TR NOX Annual allowances for a 

control period in accordance with 

paragraphs (c)(2)(i) and (ii) of this 

section, 

(A) The owner shall pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed under the 

Clean Air Act; and 

(B) Each TR NOX Annual allowance 

that the owner fails to hold for a control 

period in accordance with paragraphs 

(c)(2)(i) and (ii) of this section and each 

day of such control period shall 

constitute a separate violation of this 

subpart and the Clean Air Act. 

(3) Compliance periods. A TR NOX

Annual unit shall be subject to the 

requirements: 

(i) Under paragraph (c)(1) of this 

section for the control period starting on 

the later of January 1, 2012 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.430(b) and for each control period 

thereafter; and 

(ii) Under paragraph (c)(2) of this 

section for the control period starting on 

the later of January 1, 2014 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.430(b) and for each control period 

thereafter. 

(4) Vintage of deducted allowances. A 

TR NOX Annual allowance shall not be 

deducted, for compliance with the 

requirements under paragraphs (c)(1) 

and (2) of this section, for a control 

period in a calendar year before the year 

for which the TR NOX Annual 

allowance was allocated. 

(5) Allowance Management System 

requirements. Each TR NOX Annual 

allowance shall be held in, deducted 

from, or transferred into, out of, or 

between Allowance Management 

System accounts in accordance with 

this subpart. 

(6) Limited authorization. (i) A TR 

NOX Annual allowance is a limited 

authorization to emit one ton of NOX in 

accordance with the TR NOX Annual 

Trading Program. 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit such authorization to 

the extent the Administrator determines 

is necessary or appropriate to 

implement any provision of the Clean 

Air Act. 

(7) Property right. A TR NOX Annual 

allowance does not constitute a property 

right. 

(d) Title V Permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of TR NOX Annual 

allowances in accordance with this 

subpart. 

(2) A description of whether a unit is 

required to monitor and report NOX

emissions using a continuous emission 

monitoring system (under subpart H of 

part 75 of this chapter), an excepted 

monitoring system (under appendices D 

and E to part 75 of this chapter), a low 

mass emissions excepted monitoring 

methodology (under § 75.19 of this 

chapter), or an alternative monitoring 

system (under subpart E of part 75 of 

this chapter) in accordance with 

§§ 97.430 through 97.435 may be added 

to, or changed in, a title V permit using 

minor permit modification procedures 

in accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

the requirements applicable to the 

described monitoring and reporting (as 

added or changed, respectively) are 

already incorporated in such permit. 

This paragraph explicitly provides that 

the addition of, or change to, a unit’s 

description as described in the prior 

sentence is eligible for minor permit 

modification procedures in accordance 

with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. (1) Unless 

otherwise provided, the owners and 

operators of each TR NOX Annual 

source and each TR NOX Annual unit at 

the source shall keep on site at the 

source each of the following documents 

(in hardcopy or electronic format) for a 

period of 5 years from the date the 

document is created. This period may 

be extended for cause, at any time 


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before the end of 5 years, in writing by 

the Administrator. 

(i) The certificate of representation 

under § 97.416 for the designated 

representative for the source and each 

TR NOX Annual unit at the source and 

all documents that demonstrate the 

truth of the statements in the certificate 

of representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such 

documents are superseded because of 

the submission of a new certificate of 

representation under § 97.416 changing 

the designated representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the TR NOX Annual 

Trading Program, including any 

monitoring plans and monitoring 

system certification and recertification 

applications. 

(2) The designated representative of a 

TR NOX Annual source and each TR 

NOX Annual unit at the source shall 

make all submissions required under 

the TR NOX Annual Trading Program, 

including any submissions required for 

compliance with the TR NOX Annual 

assurance provisions. This requirement 

does not change, create an exemption 

from, or or otherwise affect the 

responsible official submission 

requirements under a title V operating 

permit program in parts 70 and 71 of 

this chapter. 

(f) Liability. (1) Any provision of the 

TR NOX Annual Trading Program that 

applies to a TR NOX Annual source or 

the designated representative of a TR 

NOX Annual source shall also apply to 

the owners and operators of such source 

and of the TR NOX Annual units at the 

source. 

(2) Any provision of the TR NOX

Annual Trading Program that applies to 

a TR NOX Annual unit or the designated 

representative of a TR NOX Annual unit 

shall also apply to the owners and 

operators of such unit. 

(g) Effect on other authorities. No 

provision of the TR NOX Annual 

Trading Program or exemption under 

§ 97.405 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of a TR NOX Annual 

source or TR NOX Annual unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.407 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Annual Trading Program, to begin on 

the occurrence of an act or event shall 

begin on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Annual Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

NOX Annual Trading Program, falls on 

a weekend or a State or Federal holiday, 

the time period shall be extended to the 

next business day. 

§ 97.408 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR NOX Annual Trading Program 

are set forth in part 78 of this chapter. 

§ 97.409 [Reserved] 

§ 97.410 State NOX Annual trading 

budgets, new-unit set-asides, and variability 

limits. 

(a) The State NOX Annual trading 

budgets and new-unit set-asides for 

allocations of TR NOX Annual 

allowances for the control periods in 

2012 and thereafter are as follows: 

State 

NOX annual 

trading budget 

(tons) * 

New-unit 

set-aside 

(tons) 

For 2012 and 

thereafter 

For 2012 and 

thereafter 

Alabama ................................................................................................................................................................... 69,169 2,075 

Connecticut .............................................................................................................................................................. 2,775 83 

Delaware .................................................................................................................................................................. 6,206 186 

District of Columbia ................................................................................................................................................. 170 5 

Florida ...................................................................................................................................................................... 120,001 3,600 

Georgia .................................................................................................................................................................... 73,801 2,214 

Illinois ....................................................................................................................................................................... 56,040 1,681 

Indiana ..................................................................................................................................................................... 115,687 3,471 

Iowa ......................................................................................................................................................................... 46,068 1,382 

Kansas ..................................................................................................................................................................... 51,321 1,540 

Kentucky .................................................................................................................................................................. 74,117 2,224 

Louisiana .................................................................................................................................................................. 43,946 1,318 

Maryland .................................................................................................................................................................. 17,044 511 

Massachusetts ......................................................................................................................................................... 5,960 179 

Michigan ................................................................................................................................................................... 64,932 1,948 

Minnesota ................................................................................................................................................................ 41,322 1,240 

Missouri .................................................................................................................................................................... 57,681 1,730 

Nebraska .................................................................................................................................................................. 43,228 1,297 

New Jersey .............................................................................................................................................................. 11,826 355 

New York ................................................................................................................................................................. 23,341 700 

North Carolina .......................................................................................................................................................... 51,800 1,554 

Ohio ......................................................................................................................................................................... 97,313 2,919 

Pennsylvania ............................................................................................................................................................ 113,903 3,417 

South Carolina ......................................................................................................................................................... 33,882 1,016 

Tennessee ............................................................................................................................................................... 28,362 851 

Virginia ..................................................................................................................................................................... 29,581 887 

West Virginia ............................................................................................................................................................ 51,990 1,560 

Wisconsin ................................................................................................................................................................. 44,846 1,345 


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State 

NOX annual 

trading budget 

(tons) * 

New-unit 

set-aside 

(tons) 

For 2012 and 

thereafter 

For 2012 and 

thereafter 

Total .................................................................................................................................................................. 1,376,312 41,288 

* Without variability limits. 

(b) The States’ one-year and three-year 

variability limits for the State NOX

Annual trading budgets for the control 

periods in 2014 and thereafter are as 

follows: 

State 

One-year 

variability 

limits 

Three-year 

variability 

limits 

2014 and 

thereafter 

(tons) 

2016 and 

thereafter 

(tons) 

Alabama ................................................................................................................................................................... 6,917 3,993 

Connecticut .............................................................................................................................................................. 5,000 2,887 

Delaware .................................................................................................................................................................. 5,000 2,887 

District of Columbia ................................................................................................................................................. 5,000 2,887 

Florida ...................................................................................................................................................................... 12,000 6,928 

Georgia .................................................................................................................................................................... 7,380 4,261 

Illinois ....................................................................................................................................................................... 5,604 3,235 

Indiana ..................................................................................................................................................................... 11,569 6,679 

Iowa ......................................................................................................................................................................... 5,000 2,887 

Kansas ..................................................................................................................................................................... 5,132 2,963 

Kentucky .................................................................................................................................................................. 7,412 4,279 

Louisiana .................................................................................................................................................................. 5,000 2,887 

Maryland .................................................................................................................................................................. 5,000 2,887 

Massachusetts ......................................................................................................................................................... 5,000 2,887 

Michigan ................................................................................................................................................................... 6,493 3,749 

Minnesota ................................................................................................................................................................ 5,000 2,887 

Missouri .................................................................................................................................................................... 5,768 3,330 

Nebraska .................................................................................................................................................................. 5,000 2,887 

New Jersey .............................................................................................................................................................. 5,000 2,887 

New York ................................................................................................................................................................. 5,000 2,887 

North Carolina .......................................................................................................................................................... 5,180 2,991 

Ohio ......................................................................................................................................................................... 9,731 5,618 

Pennsylvania ............................................................................................................................................................ 11,390 6,576 

South Carolina ......................................................................................................................................................... 5,000 2,887 

Tennessee ............................................................................................................................................................... 5,000 2,887 

Virginia ..................................................................................................................................................................... 5,000 2,887 

West Virginia ............................................................................................................................................................ 5,199 3,002 

Wisconsin ................................................................................................................................................................. 5,000 2,887 

§ 97.411 Timing requirements for TR NOX

Annual allowance allocations. 

(a) Existing units. (1) TR NOX Annual 

allowances are allocated, for the control 

periods in 2012 and each year 

thereafter, as set forth in appendix A to 

this subpart. Listing a unit in such 

appendix does not constitute a 

determination that the unit is a TR NOX

Annual unit, and not listing a unit in 

such appendix does not constitute a 

determination that the unit is not a TR 

NOX Annual unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit listed in 

appendix A to this subpart as being 

allocated TR NOX Annual allowances 

does not operate, starting after 2011, 

during the control period in three 

consecutive years, such unit will not be 

allocated the TR NOX Annual 

allowances set forth in appendix A to 

this subpart for the unit for the control 

periods in the seventh year after the first 

such year and in each year after that 

seventh year. All TR NOX Annual 

allowances that would otherwise have 

been allocated to such unit will be 

allocated to the new unit set-aside for 

the respective years involved. If such 

unit resumes operation, the 

Administrator will allocate TR NOX

Annual allowances to the unit in 

accordance with paragraph (b) of this 

section. 

(b) New units. (1) By July 1, 2012 and 

July 1 of each year thereafter, the 

Administrator will calculate the TR 

NOX Annual allowance allocation for 

each TR NOX Annual unit, in 

accordance with § 97.412, for the 

control period in the year of the 

applicable calculation deadline under 

this paragraph and will promulgate a 

notice of availability of the results of the 

calculations. 

(2) For each notice of data availability 

required in paragraph (b)(1) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations are in 

accordance with § 97.412 and 

§§ 97.406(b)(2) and 97.430 through 

97.435. 


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(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By September 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(c) Units that are not TR NOX Annual 

units. For each control period in 2012 

and thereafter, if the Administrator 

determines that TR NOX Annual 

allowances were allocated under 

paragraph (a) of this section for the 

control period to a recipient that is not 

actually a TR NOX Annual unit under 

§ 97.404 as of January 1, 2012 or whose 

deadline for meeting monitor 

certification requirements under 

§ 97.430(b)(1) and (2) is after January 1, 

2012 or if the Administrator determines 

that TR NOX Annual allowances were 

allocated under paragraph (b) of this 

section and § 97.412 for the control 

period to a recipient that is not actually 

a TR NOX Annual unit under § 97.404 

as of January 1 of the control period, 

then the Administrator will notify the 

designated representative and will act in 

accordance with the following 

procedures: 

(1) Except as provided in paragraph 

(c)(2) or (3) of this section, the 

Administrator will not record such TR 

NOX Annual allowances under § 97.421. 

(2) If the Administrator already 

recorded such TR NOX Annual 

allowances under § 97.421 and if the 

Administrator makes such 

determination before making deductions 

for the source that includes such 

recipient under § 97.424(b) for such 

control period, then the Administrator 

will deduct from the account in which 

such TR NOX Annual allowances were 

recorded an amount of TR NOX Annual 

allowances allocated for the same or a 

prior control period equal to the amount 

of such already recorded TR NOX

Annual allowances. The authorized 

account representative shall ensure that 

there are sufficient TR NOX Annual 

allowances in such account for 

completion of the deduction. 

(3) If the Administrator already 

recorded such TR NOX Annual 

allowances under § 97.421 and if the 

Administrator makes such 

determination after making deductions 

for the source that includes such 

recipient under § 97.424(b) for such 

control period, then the Administrator 

will not make any deduction to take 

account of such already recorded TR 

NOX Annual allowances. 

(4) The Administrator will transfer the 

TR NOX Annual allowances that are not 

recorded, or that are deducted, in 

accordance with paragraphs (c)(1) and 

(2) of this section to the new unit setaside, for the State in which such 

recipient is located, for the control 

period in the year of such transfer if the 

notice required in paragraph (b)(1) of 

this section for the control period in that 

year has not been promulgated or, if 

such notice has been promulgated, in 

the next year. 

§ 97.412 TR NOX Annual allowance 

allocations for new units. 

(a) For each control period in 2012 

and thereafter, the Administrator will 

allocate, in accordance with the 

following procedures, TR NOX Annual 

allowances to TR NOX Annual units in 

a State that are not listed in appendix 

A to this subpart, to TR NOX Annual 

units that are so listed and whose 

allocation of NOX Annual allowances 

for such control period is covered by 

§ 97.411(c)(1) or (2), and to TR NOX

Annual units that are so listed and, 

pursuant to § 97.411(a)(2), are not 

allocated TR NOX Annual allowances 

for such control period but operate 

during the immediately preceding 

control period: 

(1) The Administrator will establish a 

separate new unit set-aside for each 

State for each control period in a given 

year. Each new unit set-aside will be 

allocated TR NOX Annual allowances in 

an amount equal to the applicable 

amount of tons of NOX emissions as set 

forth in § 97.410(a). Each new unit setaside will be allocated additional TR 

NOX Annual allowances in accordance 

with § 97.411(a)(2) and (c)(4). 

(2) The designated representative of 

such TR NOX Annual unit may submit 

to the Administrator a request, in a 

format prescribed by the Administrator, 

to be allocated TR NOX Annual 

allowances for a control period, starting 

with the later of the control period in 

2012, the first control period after the 

control period in which the TR NOX

Annual unit commences commercial 

operation (for a unit not listed in 

appendix A to this subpart), or the first 

control period after the control period in 

which the unit resumes operation (for a 

unit listed in appendix A of this 

subpart) and for each subsequent 

control period. 

(i) The request must be submitted on 

or before May 1 of the first control 

period for which TR NOX Annual 

allowances are sought and after the date 

on which the TR NOX Annual unit 

commences commercial operation (for a 

unit not listed in appendix A of this 

subpart) or on which the unit resumes 

operation (for a unit listed in appendix 

A of this subpart). 

(ii) For each control period for which 

an allocation is sought, the request must 

be for TR NOX Annual allowances in an 

amount equal to the unit’s total tons of 

NOX emissions during the immediately 

preceding control period. 

(3) The Administrator will review 

each TR NOX Annual allowance 

allocation request under paragraph 

(a)(2) of this section and will accept the 

request only if it meets the requirements 

of paragraph (a)(2) of this section. The 

Administrator will allocate TR NOX

Annual allowances for each control 

period pursuant to an accepted request 

as follows: 

(i) After May 1 of such control period, 

the Administrator will determine the 

sum of the TR NOX Annual allowances 

requested in all accepted allowance 

allocation requests for such control 

period. 

(ii) If the amount of TR NOX Annual 

allowances in the new unit set-aside for 

such control period is greater than or 

equal to the sum under paragraph 

(a)(3)(i) of this section, then the 

Administrator will allocate the amount 

of TR NOX Annual allowances 

requested to each TR NOX Annual unit 

covered by an accepted allowance 

allocation request. 

(iii) If the amount of TR NOX Annual 

allowances in the new unit set-aside for 

such control period is less than the sum 

under paragraph (a)(3)(i) of this section, 

then the Administrator will allocate to 

each TR NOX Annual unit covered by an 

accepted allowance allocation request 

the amount of the TR NOX Annual 

allowances requested, multiplied by the 

amount of TR NOX Annual allowances 

in the new unit set-aside for such 

control period, divided by the sum 

determined under paragraph (a)(3)(i) of 

this section, and rounded to the nearest 

allowance. 

(iv) The Administrator will notify, 

through the promulgation of the notices 

of data availability described in 

§ 97.411(b), each designated 

representative that submitted an 

allowance allocation request of the 

amount of TR NOX Annual allowances 

(if any) allocated for such control period 

to the TR NOX Annual unit covered by 

the request. 

(b) If, after completion of the 

procedures under paragraph (a)(4) of 

this section for a control period, any 

unallocated TR NOX Annual allowances 

remain in the new unit set-aside under 

paragraph (a) of this section for a State 

for such control period, the 

Administrator will allocate to each TR 


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NOX Annual unit that is in the State, is 

listed in appendix A to this subpart, and 

continues to be allocated TR NOX

Annual allowances for such control 

period in accordance with 

§ 97.411(a)(2), an amount of TR NOX

Annual allowances equal to the 

following: The total amount of such 

remaining unallocated TR NOX Annual 

allowances in such new unit set-aside, 

multiplied by the unit’s allocation 

under § 97.411(a) for such control 

period, divided by the remainder of the 

amount of tons in the applicable State 

NOX Annual trading budget minus the 

amount of tons in such new unit setaside, and rounded to the nearest 

allowance. 

§ 97.413 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.415, 

each TR NOX Annual source, including 

all TR NOX Annual units at the source, 

shall have one and only one designated 

representative, with regard to all matters 

under the TR NOX Annual Trading 

Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR NOX Annual units 

at the source and shall act in accordance 

with the certification statement in 

§ 97.416(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.416: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR NOX Annual unit at the 

source in all matters pertaining to the 

TR NOX Annual Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

source and each TR NOX Annual unit at 

the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.415, 

each TR NOX Annual source may have 

one and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR NOX

Annual units at the source and shall act 

in accordance with the certification 

statement in § 97.416(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.416: 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each TR NOX Annual unit at 

the source shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(c) Except in this section, § 97.402, 

and §§ 97.414 through 97.418, whenever 

the term ‘‘designated representative’’ is 

used in this subpart, the term shall be 

construed to include the designated 

representative or any alternate 

designated representative. 

§ 97.414 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.418 

concerning delegation of authority to 

make submissions, each submission 

under the TR NOX Annual Trading 

Program shall be made, signed, and 

certified by the designated 

representative or alternate designated 

representative for each TR NOX Annual 

source and TR NOX Annual unit for 

which the submission is made. Each 

such submission shall include the 

following certification statement by the 

designated representative or alternate 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR NOX

Annual source or a TR NOX Annual unit 

only if the submission has been made, 

signed, and certified in accordance with 

paragraph (a) of this section and 

§ 97.418. 

§ 97.415 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators. 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.416. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the TR NOX Annual source 

and the TR NOX Annual units at the 

source. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.416. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the TR NOX

Annual source and the TR NOX Annual 

units at the source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a TR NOX Annual source or a TR NOX

Annual unit is not included in the list 

of owners and operators in the 

certificate of representation under 

§ 97.416, such owner or operator shall 

be deemed to be subject to and bound 

by the certificate of representation, the 

representations, actions, inactions, and 

submissions of the designated 

representative and any alternate 

designated representative of the source 

or unit, and the decisions and orders of 

the Administrator, as if the owner or 

operator were included in such list. 

(2) Within 30 days after any change in 

the owners and operators of a TR NOX

Annual source or a TR NOX Annual 

unit, including the addition of a new 


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owner or operator, the designated 

representative or any alternate 

designated representative shall submit a 

revision to the certificate of 

representation under § 97.416 amending 

the list of owners and operators to 

include the change. 

§ 97.416 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR NOX

Annual source, and each TR NOX

Annual unit at the source, for which the 

certificate of representation is 

submitted, including source name, 

source category and NAICS code (or, in 

the absence of a NAICS code, an 

equivalent code), State, plant code, 

county, latitude and longitude, unit 

identification number and type, 

identification number and nameplate 

capacity (in MWe rounded to the 

nearest tenth) of each generator served 

by each such unit, and actual or 

projected date of commencement of 

commercial operation. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR NOX Annual source and of 

each TR NOX Annual unit at the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

NOX Annual unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

NOX Annual Trading Program on behalf 

of the owners and operators of the 

source and of each TR NOX Annual unit 

at the source and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order issued to 

me by the Administrator regarding the 

source or unit.’’ 

(iii) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a TR NOX Annual 

unit, or where a utility or industrial 

customer purchases power from a TR 

NOX Annual unit under a life-of-theunit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘designated representative’ or ‘alternate 

designated representative’, as 

applicable, and of the agreement by 

which I was selected to each owner and 

operator of the source and of each TR 

NOX Annual unit at the source; and TR 

NOX Annual allowances and proceeds 

of transactions involving TR NOX

Annual allowances will be deemed to be 

held or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of TR NOX Annual 

allowances by contract, TR NOX Annual 

allowances and proceeds of transactions 

involving TR NOX Annual allowances 

will be deemed to be held or distributed 

in accordance with the contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 97.417 Objections concerning 

designated representative and alternate 

designated representative. 

(a) Once a complete certificate of 

representation under § 97.416 has been 

submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 97.416 is 

received by the Administrator. 

(b) Except as provided in § 97.415(a) 

or (b), no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the TR NOX Annual Trading 

Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of TR 

NOX Annual allowance transfers. 

§ 97.418 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (a) or (b) of this section, the 

designated representative or alternate 

designated representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to as an 

‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.418(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.418(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.418 is terminated.’’ 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 


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be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.419 [Reserved] 

§ 97.420 Establishment of Allowance 

Management System accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.416, the 

Administrator will establish a 

compliance account for the TR NOX

Annual source for which the certificate 

of representation was submitted, unless 

the source already has a compliance 

account. The designated representative 

and any alternate designated 

representative of the source shall be the 

authorized account representative and 

the alternate authorized account 

representative respectively of the 

compliance account. 

(b) General accounts—(1) Application 

for general account. 

(i) Any person may apply to open a 

general account, for the purpose of 

holding and transferring TR NOX

Annual allowances, by submitting to the 

Administrator a complete application 

for a general account. Such application 

shall designate one and only one 

authorized account representative and 

may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR NOX Annual allowances 

held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the TR NOX Annual 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR NOX Annual allowances 

held in the general account. I certify that 

I have all the necessary authority to 

carry out my duties and responsibilities 

under the TR NOX Annual Trading 

Program on behalf of such persons and 

that each such person shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

order or decision issued to me by the 

Administrator regarding the general 

account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: (A) The 

authorized account representative of the 

general account shall be authorized and 

shall represent and, by his or her 

representations, actions, inactions, or 

submissions, legally bind each person 

who has an ownership interest with 

respect to TR NOX Annual allowances 

held in the general account in all 

matters pertaining to the TR NOX

Annual Trading Program, 

notwithstanding any agreement between 

the authorized account representative 

and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to TR 

NOX Annual allowances held in the 

general account shall be bound by any 

order or decision issued to the 

authorized account representative or 

alternate authorized account 

representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph 

(b)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account shall be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to TR 

NOX Annual allowances held in the 

general account. Each such submission 

shall include the following certification 

statement by the authorized account 

representative or any alternate 

authorized account representative: ‘‘I am 

authorized to make this submission on 

behalf of the persons having an 

ownership interest with respect to the 

TR NOX Annual allowances held in the 

general account. I certify under penalty 

of law that I have personally examined, 

and am familiar with, the statements 

and information submitted in this 

document and all its attachments. Based 

on my inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 


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any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(b)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR NOX Annual 

allowances in the general account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR NOX Annual allowances in the 

general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR NOX Annual allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such person shall 

be deemed to be subject to and bound 

by the application for a general account, 

the representation, actions, inactions, 

and submissions of the authorized 

account representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to NOX Annual 

allowances in the general account, 

including the addition of a new person, 

the authorized account representative or 

any alternate authorized account 

representative shall submit a revision to 

the application for a general account 

amending the list of persons having an 

ownership interest with respect to the 

TR NOX Annual allowances in the 

general account to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. (i) 

Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account shall affect any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative or the 

finality of any decision or order by the 

Administrator under the TR NOX

Annual Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

NOX Annual allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (b)(5)(i) or (ii) of this section, 

the authorized account representative or 

alternate authorized account 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(B) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such natural person (referred to 

as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (b)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 

97.420(b)(5)(iv) shall be deemed to be an 

electronic submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 40 

CFR 97.420(b)(5)(iv), I agree to maintain 

an e-mail account and to notify the 

Administrator immediately of any 

change in my e-mail address unless all 

delegation of authority by me under 40 

CFR 97.420(b)(5) is terminated.’’. 

(iv) A notice of delegation submitted 

under paragraph (b)(5)(iii) of this 

section shall be effective, with regard to 

the authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

(v) Any electronic submission covered 

by the certification in paragraph 

(b)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (b)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 


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representative or alternate designated 

representative submitting such notice of 

delegation. 

(6)(i) The authorized account 

representative or alternate authorized 

account representative of a general 

account may submit to the 

Administrator a request to close the 

account. Such request shall include a 

correctly submitted TR NOX Annual 

allowance transfer under § 97.422 for 

any TR NOX Annual allowances in the 

account to one or more other Allowance 

Management System accounts. 

(ii) If a general account has no TR 

NOX Annual allowance transfers to or 

from the account for a 12-month period 

or longer and does not contain any TR 

NOX Annual allowances, the 

Administrator may notify the authorized 

account representative for the account 

that the account will be closed after 20 

business days after the notice is sent. 

The account will be closed after the 20- 

day period unless, before the end of the 

20-day period, the Administrator 

receives a correctly submitted TR NOX

Annual allowance transfer under 

§ 97.422 to the account or a statement 

submitted by the authorized account 

representative or alternate authorized 

account representative demonstrating to 

the satisfaction of the Administrator 

good cause as to why the account 

should not be closed. 

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section. 

(d) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of an Allowance 

Management System account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of TR NOX Annual 

allowances in the account, only if the 

submission has been made, signed, and 

certified in accordance with §§ 97.414(a) 

and 97.418 or paragraphs (b)(2)(ii) and 

(b)(5) of this section. 

§ 97.421 Recordation of TR NOX Annual 

allowance allocations. 

(a) By September 1, 2011, the 

Administrator will record in each TR 

NOX Annual source’s compliance 

account the TR NOX Annual allowances 

allocated for the TR NOX Annual units 

at the source in accordance with 

§§ 97.411(a) for the control periods in 

2012, 2013, and 2014. 

(b) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

record in each TR NOX Annual source’s 

compliance account the TR NOX Annual 

allowances allocated for the TR NOX

Annual units at the source in 

accordance with § 97.411(a) for the 

control period in the third year after the 

year of the applicable recordation 

deadline under this paragraph. 

(c) By September 1, 2012 and 

September 1 of each year thereafter, the 

Administrator will record in each TR 

NOX Annual source’s compliance 

account the TR NOX Annual allowances 

allocated for the TR NOX Annual units 

at the source in accordance with 

§ 97.412 for the control period in the 

year of the applicable recordation 

deadline under this paragraph. 

(d) When recording the allocation of 

TR NOX Annual allowances for a TR 

NOX Annual unit in a compliance 

account, the Administrator will assign 

each TR NOX Annual allowance a 

unique identification number that will 

include digits identifying the year of the 

control period for which the TR NOX

Annual allowance is allocated. 

§ 97.422 Submission of TR NOX Annual 

allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR NOX Annual allowance transfer shall 

submit the transfer to the Administrator. 

(b) A TR NOX Annual allowance 

transfer shall be correctly submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR NOX

Annual allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR NOX Annual 

allowance identified by serial number in 

the transfer. 

§ 97.423 Recordation of TR NOX Annual 

allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR NOX Annual 

allowance transfer, the Administrator 

will record a TR NOX Annual allowance 

transfer by moving each TR NOX

Annual allowance from the transferor 

account to the transferee account as 

specified by the request, provided that 

the transfer is correctly submitted under 

§ 97.422. 

(b)(1) A TR NOX Annual allowance 

transfer that is submitted for recordation 

after the allowance transfer deadline for 

a control period and that includes any 

TR NOX Annual allowances allocated 

for any control period before such 

allowance transfer deadline will not be 

recorded until after the Administrator 

completes the deductions under 

§ 97.424 for the control period 

immediately before such allowance 

transfer deadline. 

(2) A TR NOX Annual allowance 

transfer that is submitted for recordation 

after the deadline for holding TR NOX

Annual allowances described in 

§ 97.425(b)(5) and that includes any TR 

NOX Annual allowances allocated for a 

control period before the year of such 

deadline will not be recorded until after 

the Administrator completes the 

deductions under § 97.425 for the 

control period immediately before the 

year of such deadline. 

(c) Where a TR NOX Annual 

allowance transfer is not correctly 

submitted under § 97.422, the 

Administrator will not record such 

transfer. 

(d) Within 5 business days of 

recordation of a TR NOX Annual 

allowance transfer under paragraphs (a) 

and (b) of the section, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR NOX Annual allowance transfer 

that is not correctly submitted under 

§ 97.422, the Administrator will notify 

the authorized account representatives 

of both accounts subject to the transfer 

of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.424 Compliance with TR NOX Annual 

emissions limitation. 

(a) Availability for deduction for 

compliance. TR NOX Annual 

allowances are available to be deducted 

for compliance with a source’s TR NOX

Annual emissions limitation for a 

control period in a given year only if the 

TR NOX Annual allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in the source’s 

compliance account as of the allowance 

transfer deadline for such control 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 97.423, of TR NOX Annual allowance 

transfers submitted by the allowance 

transfer deadline for a control period, 

the Administrator will deduct from the 

compliance account TR NOX Annual 

allowances available under paragraph 


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(a) of this section in order to determine 

whether the source meets the TR NOX

Annual emissions limitation for such 

control period, as follows: 

(1) Until the amount of TR NOX

Annual allowances deducted equals the 

number of tons of total NOX emissions 

from all TR NOX Annual units at the 

source for such control period; or 

(2) If there are insufficient TR NOX

Annual allowances to complete the 

deductions in paragraph (b)(1) of this 

section, until no more TR NOX Annual 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(c)(1) Identification of TR NOX

Annual allowances by serial number. 

The authorized account representative 

for a source’s compliance account may 

request that specific TR NOX Annual 

allowances, identified by serial number, 

in the compliance account be deducted 

for emissions or excess emissions for a 

control period in accordance with 

paragraph (b) or (d) of this section. In 

order to be complete, such request shall 

be submitted to the Administrator by 

the allowance transfer deadline for such 

control period and include, in a format 

prescribed by the Administrator, the 

identification of the TR NOX Annual 

source and the appropriate serial 

numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR NOX

Annual allowances under paragraph (b) 

or (d) of this section from the source’s 

compliance account in accordance with 

a complete request under paragraph 

(c)(1) of this section or, in the absence 

of such request or in the case of 

identification of an insufficient amount 

of TR NOX Annual allowances in such 

request, on a first-in, first-out (FIFO) 

accounting basis in the following order: 

(i) Any TR NOX Annual allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR NOX Annual allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a year in 

which the TR NOX Annual source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account an amount of TR NOX Annual 

allowances, allocated for the control 

period in the immediately following 

year, equal to two times the number of 

tons of the source’s excess emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.425 Compliance with TR NOX Annual 

assurance provisions. 

(a) Availability for deduction. TR NOX

Annual allowances are available to be 

deducted for compliance with the TR 

NOX Annual assurance provisions for a 

control period in a given year by an 

owner of one or more TR NOX Annual 

units in a State only if the TR NOX

Annual allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in a compliance account, 

designated by the owner in accordance 

with paragraph (b)(4)(ii) of this section, 

of one of the owner’s TR NOX Annual 

sources in the State as of the deadline 

established in paragraph (b)(5) of this 

section. 

(b) Deductions for compliance. The 

Administrator will deduct TR NOX

Annual allowances available under 

paragraph (a) of this section for 

compliance with the TR NOX Annual 

assurance provisions for a State for a 

control period in a given year in 

accordance with the following 

procedures: 

(1) By June 1, 2015 and June 1 of each 

year thereafter, the Administrator will: 

(i) Calculate, separately for each State, 

the total amount of NOX emissions from 

all TR NOX Annual units in the State 

during the control period in the year 

before the year of this calculation 

deadline and the amount, if any, by 

which such total amount of NOX

emissions exceeds the State assurance 

level as described in § 97.406(c)(2)(iii); 

and 

(ii) Promulgate a notice of availability 

of the results of the calculations 

required in paragraph (b)(1)(i) of this 

section, including separate calculations 

of the NOX emissions for each TR NOX

Annual unit and of the amounts 

described in §§ 97.406(c)(2)(iii)(A) and 

(B) for each State. 

(2) The Administrator will provide an 

opportunity for submission of objections 

to the calculations referenced by each 

notice described in paragraph (b)(1) of 

this section. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each TR 

NOX Annual unit and each State for the 

control period in the year involved are 

in accordance with § 97.406(c)(2)(iii) 

and §§ 97.406(b) and 97.430 through 

97.435. 

(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By August 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(3) For each notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and for any State identified in 

such notice as having TR NOX Annual 

sources with total NOX emissions 

exceeding the State assurance level for 

a control period, as described in 

§ 97.406(c)(2)(iii): 

(i) By August 15 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

NOX Annual source in each such State 

shall submit a statement, in a format 

prescribed by the Administrator: 

(A) Listing all the owners of each TR 

NOX Annual unit at the source, 

explaining how the selection of each 

owner for inclusion on the list is 

consistent with the definition of 

‘‘owner’’ in § 97.402, and listing, 

separately for each unit, the percentage 

of the legal, equitable, leasehold, or 

contractual reservation or entitlement 

for each such owner as of midnight of 

December 31 of the control period in the 

year involved; and 

(B) For each TR NOX Annual unit at 

the source that operates during, but is 

allocated no TR NOX Annual 

allowances for, the control period in the 

year involved, identifying whether the 

unit is a coal-fired boiler, simple 

combustion turbine, or combined cycle 

turbine cycle and providing the unit’s 

allowable NOX emission rate for such 

control period. 

(ii) By September 15 immediately 

after the promulgation of such notice, 

the Administrator will calculate, for 

each such State and each owner of one 

or more TR NOX Annual units in the 

State and for the control period in the 

year involved, each owner’s share of the 

total NOX emissions from all TR NOX

Annual units in the State, each owner’s 

assurance level, and the amount (if any) 

of TR NOX Annual allowances that each 

owner must hold in accordance with the 

calculation formula in § 97.406(c)(2)(i) 

and will promulgate a notice of 

availability of the results of these 

calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 


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required in paragraph (b)(3)(ii) of this 

section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each owner 

for the control period in the year 

involved are consistent with the NOX

emissions for the relevant TR NOX

Annual units as set forth in the notice 

required in paragraph (b)(2)(ii) of this 

section, the definitions of ‘‘owner’’, 

‘‘owner’s assurance level’’, and ‘‘owner’s 

share’’ in § 97.402, and the calculation 

formula in § 97.406(c)(2)(i) and shall not 

raise any issues about any data used in 

the notice of data availability required 

in paragraph (b)(2)(ii) of this section. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are consistent with the 

data and provisions referenced in 

paragraph (b)(3)(iii)(A) of this section. 

By November 15 immediately after the 

promulgation of such notice, the 

Administrator will promulgate a notice 

of availability of any adjustments that 

the Administrator determines to be 

necessary and the reasons for accepting 

or rejecting any objections submitted in 

accordance with paragraph (b)(3)(iii)(A) 

of this section. 

(4) By December 1 immediately after 

the promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section: 

(i) Each owner identified, in such 

notice, as owning one or more TR NOX

Annual units in a State and as being 

required to hold TR NOX Annual 

allowances shall designate the 

compliance account of one of the 

sources at which such unit or units are 

located to hold such required TR NOX

Annual allowances; 

(ii) The authorized account 

representative for the compliance 

account designated under paragraph 

(b)(4)(i) of this section shall submit to 

the Administrator a statement, in a 

format prescribed by the Administrator, 

making this designation. 

(5)(i) As of midnight of December 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(3)(iii)(B) of this section, 

each owner described in paragraph 

(b)(4)(i) of this section shall hold in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section the total amount 

of TR NOX Annual allowances, available 

for deduction under paragraph (a) of 

this section, equal to the amount the 

owner is required to hold as calculated 

by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(5)(i) of this section, if December 15 

is not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(6) After December 15 (or the date 

described in paragraph (b)(5)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.423, of TR NOX Annual allowance 

transfers submitted by midnight of such 

date, the Administrator will deduct 

from each compliance account 

designated in accordance with 

paragraph (b)(4)(ii) of this section, TR 

NOX Annual allowances available under 

paragraph (a) of this section, as follows: 

(i) Until the amount of TR NOX

Annual allowances deducted equals the 

amount that the owner designating the 

compliance account is required to hold 

as calculated by the Administrator and 

referenced in the notice required in 

paragraph (b)(3)(iii)(B) of this section; or 

(ii) If there are insufficient TR NOX

Annual allowances to complete the 

deductions in paragraph (b)(6)(i) of this 

section, until no more TR NOX Annual 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(7) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notices of data availability required 

in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) 

of this section respectively for a control 

period, of any data used in making the 

calculations referenced in such notice, 

the amount of TR NOX Annual 

allowances that each owner is required 

to hold in accordance with 

§ 97.406(c)(2)(i) for the control period in 

the year involved shall continue to be 

such amount as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(3)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR NOX Annual allowances that 

owners are required to hold in 

accordance with the calculation formula 

in § 97.406(c)(2)(i) for the control period 

in the year involved with regard to the 

State involved, provided that— 

(A) With regard to such litigation 

involving such notice required in 

paragraph (b)(2)(ii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(ii) of this section; and 

(B) With regard to such litigation 

involving such notice required in 

paragraph (b)(3)(iii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(3)(iii) of this section. 

(ii) If any such data are revised by the 

owners and operators of a source whose 

designated representative submitted 

such data under paragraph (b)(3)(i) of 

this section, as a result of a decision in 

or settlement of litigation concerning 

such submission, then the 

Administrator will use the data as so 

revised to recalculate the amounts of TR 

NOX Annual allowances that owners are 

required to hold in accordance with the 

calculation formula in § 97.406(c)(2)(i) 

for the control period in the year 

involved with regard to the State 

involved, provided that such litigation 

was initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(3)(iii)(B) of this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(7)(i) and (b)(7)(ii) of this 

section, the amount of TR NOX Annual 

allowances that an owner is required to 

hold for the control period in the year 

involved with regard to the State 

involved- 

(A) Where the amount of TR NOX

Annual allowances that an owner is 

required to hold increases as a result of 

the use of all such revised data, the 

Administrator will establish a new, 

reasonable deadline on which the owner 

shall hold the additional amount of TR 

NOX Annual allowances in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section. The owner’s 

failure to hold such additional amount, 

as required, before the new deadline 

shall not be a violation of the Clean Air 

Act. The owner’s failure to hold such 

additional amount, as required, as of the 

new deadline shall be a violation of the 

Clean Air Act. Each TR NOX Annual 

allowance that the owner fails to hold 

as required as of the new deadline, and 

each day in the control period in the 


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year involved, shall be a separate 

violation of the Clean Air Act. After 

such deadline, the Administrator will 

make the appropriate deductions from 

the compliance account. 

(B) For an owner for which the 

amount of TR NOX Annual allowances 

required to be held decreases as a result 

of the use of all such revised data, the 

Administrator will record, in the 

compliance account that the owner 

designated in accordance with 

paragraph (b)(4)(ii) of this section, an 

amount of TR NOX Annual allowances 

equal to the amount of the decrease to 

the extent such amount was previously 

deducted from the compliance account 

under paragraph (b)(6) of this section 

(and has not already been restored to the 

compliance account) for the control 

period in the year involved. 

(C) Each TR NOX Annual allowance 

held and deducted under paragraph 

(b)(7)(iii)(A) of this section, or recorded 

under paragraph (b)(7)(iii)(B) of this 

section, as a result of recalculation of 

requirements under the TR NOX Annual 

assurance provisions for a control 

period in a given year must be a TR NOX

Annual allowance allocated for a 

control period in the same or a prior 

year. 

(c)(1) Identification of TR NOX

Annual allowances by serial number. 

The authorized account representative 

for each source’s compliance account 

designated in accordance with 

paragraph (b)(4)(ii) of this section may 

request that specific TR NOX Annual 

allowances, identified by serial number, 

in the compliance account be deducted 

in accordance with paragraph (b)(6) or 

(7) of this section. In order to be 

complete, such request shall be 

submitted to the Administrator by the 

allowance-holding deadline described 

in paragraph (b)(5) of this section and 

include, in a format prescribed by the 

Administrator, the identification of the 

compliance account and the appropriate 

serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR NOX

Annual allowances under paragraphs 

(b)(6) and (7) of this section from each 

source’s compliance account designated 

under paragraph (b)(4)(ii) of this section 

in accordance with a complete request 

under paragraph (c)(1) of this section or, 

in the absence of such request or in the 

case of identification of an insufficient 

amount of TR NOX Annual allowances 

in such request, on a first-in, first-out 

(FIFO) accounting basis in the following 

order: 

(i) Any TR NOX Annual allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR NOX Annual allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) of this section. 

§ 97.426 Banking. 

(a) A TR NOX Annual allowance may 

be banked for future use or transfer in 

a compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any TR NOX Annual allowance 

that is held in a compliance account or 

a general account will remain in such 

account unless and until the TR NOX

Annual allowance is deducted or 

transferred under § 97.411(c), § 97.423, 

§ 97.424, § 97.425, 97.427, 97.428, 

97.442, or 97.443. 

§ 97.427 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.428 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR NOX

Annual Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

NOX Annual allowances from or transfer 

TR NOX Annual allowances to a 

source’s compliance account based on 

the information in a submission, as 

adjusted under paragraph (a)(1) of this 

section, and record such deductions and 

transfers. 

§ 97.429 [Reserved] 

§ 97.430 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR NOX Annual 

unit, shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and subpart H of part 75 of this chapter. 

For purposes of applying such 

requirements, the definitions in § 97.402 

and in § 72.2 of this chapter shall apply, 

the terms ‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘TR NOX

Annual unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively as defined in 

§ 97.402, and the term ‘‘newly affected 

unit’’ shall be deemed to mean ‘‘newly 

affected TR NOX Annual unit’’. The 

owner or operator of a unit that is not 

a TR NOX Annual unit but that is 

monitored under § 75.72(b)(2)(ii) of this 

chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a TR NOX

Annual unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR NOX

Annual unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring NOX mass emissions and 

individual unit heat input (including all 

systems required to monitor NOX

emission rate, NOX concentration, stack 

gas moisture content, stack gas flow 

rate, CO2 or O2 concentration, and fuel 

flow rate, as applicable, in accordance 

with §§ 75.71 and 75.72 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.431 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates and shall record, 

report, and quality-assure the data from 

the monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

NOX Annual unit that commences 

commercial operation before July 1, 

2011, January 1, 2012; 

(2) For the owner or operator of a TR 

NOX Annual unit that commences 

commercial operation on or after July 1, 

2011, the later of the following: 

(i) January 1, 2012; or 

(ii) 180 calendar days, whichever 

occurs first, after the date on which the 

unit commences commercial operation; 

(3) For the owner or operator of a TR 

NOX Annual unit for which 

construction of a new stack or flue or 

installation of add-on NOX emission 


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controls is completed after the 

applicable deadline under paragraph 

(b)(1) or (2) of this section, by 90 unit 

operating days or 180 calendar days, 

whichever occurs first, after the date on 

which emissions first exit to the 

atmosphere through the new stack or 

flue or add-on NOX emissions controls; 

(4) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a unit for 

which a TR opt-in application is 

submitted and not withdrawn and is not 

yet approved or disapproved, by the 

date specified in § 97.441(c); and 

(5) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a TR NOX

Annual opt-in unit, by the date on 

which the TR NOX Annual opt-in unit 

enters the TR NOX Annual Trading 

Program as provided in § 97.441(h). 

(c) Reporting data. The owner or 

operator of a TR NOX Annual unit that 

does not meet the applicable 

compliance date set forth in paragraph 

(b) of this section for any monitoring 

system under paragraph (a)(1) of this 

section shall, for each such monitoring 

system, determine, record, and report 

maximum potential (or, as appropriate, 

minimum potential) values for NOX

concentration, NOX emission rate, stack 

gas flow rate, stack gas moisture 

content, fuel flow rate, and any other 

parameters required to determine NOX

mass emissions and heat input in 

accordance with § 75.31(b)(2) or (c)(3) of 

this chapter, section 2.4 of appendix D 

to part 75 of this chapter, or section 2.5 

of appendix E to part 75 of this chapter, 

as applicable. 

(d) Prohibitions. (1) No owner or 

operator of a TR NOX Annual unit shall 

use any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this subpart without having obtained 

prior written approval in accordance 

with § 97.435. 

(2) No owner or operator of a TR NOX

Annual unit shall operate the unit so as 

to discharge, or allow to be discharged, 

NOX emissions to the atmosphere 

without accounting for all such 

emissions in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter. 

(3) No owner or operator of a TR NOX

Annual unit shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording NOX mass emissions 

discharged into the atmosphere or heat 

input, except for periods of 

recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the applicable provisions of this 

subpart and part 75 of this chapter. 

(4) No owner or operator of a TR NOX

Annual unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.405 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.431(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR NOX Annual unit is 

subject to the applicable provisions of 

§ 75.4(d) of this chapter concerning 

units in long-term cold storage. 

§ 97.431 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR NOX

Annual unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 97.430(a)(1) if the following conditions 

are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B, D, and E to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.430(a)(1) that is 

exempt from initial certification 

requirements under paragraph (a) of this 

section. 

(c) If the Administrator has previously 

approved a petition under § 75.17(a) or 

(b) of this chapter for apportioning the 

NOX emission rate measured in a 

common stack or a petition under 

§ 75.66 of this chapter for an alternative 

to a requirement in § 75.12 or § 75.17 of 

this chapter, the designated 

representative shall resubmit the 

petition to the Administrator under 

§ 97.435 to determine whether the 

approval applies under the TR NOX

Annual Trading Program. 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR NOX Annual unit shall comply 

with the following initial certification 

and recertification procedures for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendices D and E to part 75 of 

this chapter) under § 97.430(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.430(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.430(b). 

In addition, whenever the owner or 

operator installs a monitoring system to 

meet the requirements of this subpart in 

a location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.430(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record NOX mass emissions or heat 

input rate or to meet the qualityassurance and quality-control 

requirements of § 75.21 of this chapter 

or appendix B to part 75 of this chapter, 

the owner or operator shall recertify the 

monitoring system in accordance with 

§ 75.20(b) of this chapter. Furthermore, 

whenever the owner or operator makes 

a replacement, modification, or change 

to the flue gas handling system or the 

unit’s operation that may significantly 

change the stack flow or concentration 

profile, the owner or operator shall 

recertify each continuous emission 

monitoring system whose accuracy is 

potentially affected by the change, in 

accordance with § 75.20(b) of this 

chapter. Examples of changes to a 

continuous emission monitoring system 

that require recertification include 

replacement of the analyzer, complete 


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replacement of an existing continuous 

emission monitoring system, or change 

in location or orientation of the 

sampling probe or site. Any fuel 

flowmeter system, and any excepted 

NOX monitoring system under appendix 

E to part 75 of this chapter, under 

§ 97.430(a)(1) are subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.430(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 

procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word ‘‘certified’’ 

is replaced by with the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.433. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR NOX Annual Trading Program 

for a period not to exceed 120 days after 

receipt by the Administrator of the 

complete certification application for 

the monitoring system under paragraph 

(d)(3)(ii) of this section. Data measured 

and recorded by the provisionally 

certified monitoring system, in 

accordance with the requirements of 

part 75 of this chapter, will be 

considered valid quality-assured data 

(retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR NOX Annual Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. The 120-day 

review period specified in paragraph 

(d)(3) of this section shall not begin 

before receipt of a complete certification 

application. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.432(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved NOX emission 

rate (i.e., NOX-diluent) system, the 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(2) For a disapproved NOX pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

NOX and the maximum potential flow 

rate, as defined in sections 2.1.2.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(3) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(4) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(5) For a disapproved excepted NOX

monitoring system under appendix E to 

part 75 of this chapter, the fuel-specific 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 


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a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.432 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or subpart H of, or appendix 

D or appendix E to, part 75 of this 

chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.431 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

Administrator or any permitting 

authority. By issuing the notice of 

disapproval, the Administrator revokes 

prospectively the certification status of 

the monitoring system. The data 

measured and recorded by the 

monitoring system shall not be 

considered valid quality-assured data 

from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 97.431 for each 

disapproved monitoring system. 

§ 97.433 Notifications concerning 

monitoring. 

The designated representative of a TR 

NOX Annual unit shall submit written 

notice to the Administrator in 

accordance with § 75.61 of this chapter. 

§ 97.434 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in paragraphs (b) through 

(e) of this section, the applicable 

recordkeeping and reporting 

requirements under § 75.73 of this 

chapter, and the requirements of 

§ 97.414(a). 

(b) Monitoring plans. The owner or 

operator of a TR NOX Annual unit shall 

comply with requirements of § 75.73(c) 

and (e) of this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.431, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) The designated representative 

shall report the NOX mass emissions 

data and heat input data for the TR NOX

Annual unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering 

January 1, 2012 through March 31, 2012; 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.430(b), unless 

that quarter is the third or fourth quarter 

of 2011, in which case reporting shall 

commence in the quarter covering 

January 1, 2012 through March 31, 2012; 

(iii) Notwithstanding paragraphs 

(d)(1)(i) and (ii) of this section, for a unit 

for which a TR opt-in application is 

submitted and not withdrawn and is not 

yet approved or disapproved, the 

calendar quarter corresponding to the 

date specified in § 97.441(c); and 

(iv) Notwithstanding paragraphs 

(d)(1)(i) and (ii) of this section, for a TR 

NOX Annual opt-in unit, the calendar 

quarter corresponding to the date on 

which the TR NOX Annual opt-in unit 

enters the TR NOX Annual Trading 

Program as provided in § 97.441(h). 

(2) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.73(f) of this chapter. 

(3) For TR NOX Annual units that are 

also subject to the Acid Rain Program, 

TR NOX Ozone Season Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 2 Trading 

Program, quarterly reports shall include 

the applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the NOX mass emission data, 

heat input data, and other information 

required by this subpart. 

(4) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(ii) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(2) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 


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unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on NOX

emission controls and for all hours 

where NOX data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate 

NOX emissions. 

§ 97.435 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR NOX Annual unit may submit a 

petition under § 75.66 of this chapter to 

the Administrator, requesting approval 

to apply an alternative to any 

requirement of §§ 97.430 through 97.434 

or paragraph (5)(i) or (ii) of the 

definition of ‘‘owner’s share’’ in 

§ 97.402. 

(b) A petition submitted under 

paragraph (a) of this section shall 

include sufficient information for the 

evaluation of the petition, including, at 

a minimum, the following information: 

(i) Identification of each unit and 

source covered by the petition; 

(ii) A detailed explanation of why the 

proposed alternative is being suggested 

in lieu of the requirement; 

(iii) A description and diagram of any 

equipment and procedures used in the 

proposed alternative; 

(iv) A demonstration that the 

proposed alternative is consistent with 

the purposes of the requirement for 

which the alternative is proposed and 

with the purposes of this subpart and 

part 75 of this chapter and that any 

adverse effect of approving the 

alternative will be de minimis; and 

(v) Any other relevant information 

that the Administrator may require. 

(c) Use of an alternative to any 

requirement referenced in paragraph (a) 

of this section is in accordance with this 

subpart only to the extent that the 

petition is approved in writing by the 

Administrator and that such use is in 

accordance with such approval. 

§ 97.440 General requirements for TR NOX

Annual opt-in units. 

(a) A TR NOX Annual opt-in unit 

must be a unit that: 

(1) Is located in a State; 

(2) Is not a TR NOX Annual unit 

under § 97.404; 

(3) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; and 

(4) Vents all of its emissions to a stack 

and can meet the monitoring, 

recordkeeping, and reporting 

requirements of this subpart. 

(b) A TR NOX Annual opt-in unit 

shall be deemed to be a TR NOX Annual 

unit for purposes of applying this 

subpart, except for §§ 97.405, 97.411, 

and 97.412. 

(c) Solely for purposes of applying the 

requirements of §§ 97.413 through 

97.418 and §§ 97.430 through 97.435, a 

unit for which a TR opt-in application 

is submitted and not withdrawn and is 

not yet approved or disapproved under 

§ 97.442 shall be deemed to be a TR 

NOX Annual unit. 

(d) Any TR NOX Annual opt-in unit, 

and any unit for which a TR opt-in 

application is submitted and not 

withdrawn and is not yet approved or 

disapproved under § 97.442, located at 

the same source as one or more TR NOX

Annual units shall have the same 

designated representative and alternate 

designated representative as such TR 

NOX Annual units. 

§ 97.441 Opt-In process. 

A unit meeting the requirements for a 

TR NOX Annual opt-in unit in 

§ 97.440(a) may become a TR NOX

Annual opt-in unit only if, in 

accordance with this section, the 

designated representative of the unit 

submits a complete TR opt-in 

application for the unit and the 

Administrator approves the application. 

(a) Applying to opt in. The designated 

representative of the unit may submit a 

complete TR opt-in application for the 

unit at any time, except as provided 

under § 97.442(e). A complete TR opt-in 

application shall include the following 

elements in a format prescribed by the 

Administrator: 

(1) Identification of the unit and the 

source where the unit is located, 

including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, and unit identification 

number and type; 

(2) A certification that the unit: 

(i) Is not a TR NOX Annual unit under 

§ 97.404; 

(ii) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(iii) Vents all of its emissions to a 

stack; and 

(iv) Has documented heat input 

(greater than 0 mmBtu) for more than 

876 hours during the 6 months 

immediately preceding submission of 

the TR opt-in application; 

(3) A monitoring plan in accordance 

with §§ 97.430 through 97.435; 

(4) A statement that the unit, if 

approved to become a TR NOX Annual 

unit under paragraph (g) of this section, 

may withdraw from the TR NOX Annual 

Trading Program only in accordance 

with § 97.442; 

(5) A statement that the unit, if 

approved to become a TR NOX Annual 

unit under paragraph (g) of this section, 

is subject to, and the owners and 

operators of the unit must comply with, 

the requirements of § 97.443; 

(6) A complete certificate of 

representation under § 97.416 consistent 

with § 97.440, if no designated 

representative has been previously 

designated for the source that includes 

the unit; and 

(7) The signature of the designated 

representative and the date signed. 

(b) Interim review of monitoring plan. 

The Administrator will determine, on 

an interim basis, the sufficiency of the 

monitoring plan submitted under 

paragraph (a)(3) of this section. The 

monitoring plan is sufficient, for 

purposes of interim review, if the plan 

appears to contain information 

demonstrating that the NOX emission 

rate and heat input of the unit and all 

other applicable parameters are 

monitored and reported in accordance 

with §§ 97.430 through 97.435. A 

determination of sufficiency shall not be 

construed as acceptance or approval of 

the monitoring plan. 

(c) Monitoring and reporting. (1)(i) If 

the Administrator determines that the 

monitoring plan is sufficient under 

paragraph (b) of this section, the owner 

or operator of the unit shall monitor and 

report the NOX emission rate and the 

heat input of the unit and all other 

applicable parameters, in accordance 

with §§ 97.430 through 97.435, starting 

on the date of certification of the 

necessary monitoring systems under 

§§ 97.430 through 97.435 and 

continuing until the TR opt-in 

application submitted under paragraph 

(a) of this section is disapproved under 

this section or, if such TR opt-in 

application is approved, the date and 

time when the unit is withdrawn from 

the TR NOX Annual Trading Program in 

accordance with § 97.442. 

(ii) The monitoring and reporting 

under paragraph (c)(1)(i) of this section 

shall cover the entire control period 

immediately before the date on which 

the unit enters the TR NOX Annual 

Trading Program under paragraph (h) of 

this section, during which period 

monitoring system availability must not 


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be less than 98 percent under §§ 97.430 

through 97.435 and the unit must be in 

full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(2) To the extent the NOX emission 

rate and the heat input of the unit are 

monitored and reported in accordance 

with §§ 97.430 through 97.435 for one or 

more entire control periods, in addition 

to the control period under paragraph 

(c)(1)(ii) of this section, during which 

control periods monitoring system 

availability is not less than 98 percent 

under §§ 97.430 through 97.435 and the 

unit is in full compliance with any 

applicable State or Federal emissions or 

emissions-related requirements and 

which control periods begin not more 

than 3 years before the unit enters the 

TR NOX Annual Trading Program under 

paragraph (h) of this section, such 

information shall be used as provided in 

paragraphs (e) and (f) of this section. 

(d) Statement on compliance. After 

submitting to the Administrator all 

quarterly reports required for the unit 

under paragraph (c) of this section, the 

designated representative shall submit, 

in a format prescribed by the 

Administrator, to the Administrator a 

statement that, for the years covered by 

such quarterly reports, the unit was in 

full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(e) Baseline heat input. The unit’s 

baseline heat input shall equal: 

(1) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for only one entire control period, in 

accordance with paragraph (c) of this 

section, the unit’s total heat input (in 

mmBtu) for such control period; or 

(2) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, the average of the amounts of 

the unit’s total heat input (in mmBtu) 

for such control periods. 

(f) Baseline NOX emission rate. The 

unit’s baseline NOX emission rate shall 

equal: 

(1) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for only one entire control period, in 

accordance with paragraph (c) of this 

section, the unit’s NOX emission rate (in 

lb/mmBtu) for such control period; 

(2) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit does not have addon NOX emission controls during any 

such control periods, the average of the 

amounts of the unit’s NOX emission rate 

(in lb/mmBtu) for such control periods; 

or 

(3) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit has add-on NOX

emission controls during any such 

control periods, the average of the 

amounts of the unit’s NOX emission rate 

(in lb/mmBtu) for such control periods 

during which the unit has add-on NOX

emission controls. 

(g) Review of TR opt-in application. 

(1) After the designated representative 

submits the complete TR opt-in 

application, quarterly reports, and 

statement required in paragraphs (a), (c), 

and (d) of this section and if the 

Administrator determines that the 

designated representative shows that the 

unit meets the requirements for a TR 

NOX Annual opt-in unit in § 97.440, the 

element certified in paragraph (a)(2)(iv) 

of this section, and the monitoring and 

reporting requirements of paragraph (c) 

of this section, the Administrator will 

issue a written approval of the TR optin application for the unit. The written 

approval will state the unit’s baseline 

heat input and baseline NOX emission 

rate. The Administrator will thereafter 

establish a compliance account for the 

source that includes the unit unless the 

source already has a compliance 

account. 

(2) Notwithstanding paragraphs (a) 

through (f) of this section, if, at any time 

before the TR opt-in application is 

approved under paragraph (g)(1) of this 

section, the Administrator determines 

that the unit cannot meet the 

requirements for a TR NOX Annual optin unit in § 97.440, the element certified 

in paragraph (a)(2)(iv) of this section, or 

the monitoring and reporting 

requirements in paragraph (c) of this 

section, the Administrator will issue a 

written disapproval of the TR opt-in 

application for the unit. 

(h) Date of entry into TR NOX Annual 

Trading Program. A unit for which a TR 

opt-in application is approved under 

paragraph (g)(1) of this section shall 

become a TR NOX Annual opt-in unit, 

and a TR NOX Annual unit, effective as 

of the later of January 1, 2012 or January 

1 of the first control period during 

which such approval is issued. 

§ 97.442 Withdrawal of TR NOX Annual 

opt-in unit from TR NOX Annual Trading 

Program. 

A TR NOX Annual opt-in unit may 

withdraw from the TR NOX Annual 

Trading Program only if, in accordance 

with this section, the designated 

representative of the unit submits a 

request to withdraw the unit and the 

Administrator issues a written approval 

of the request. 

(a) Requesting withdrawal. In order to 

withdraw the TR NOX Annual opt-in 

unit from the TR NOX Annual Trading 

Program, the designated representative 

of the unit shall submit to the 

Administrator a request to withdraw the 

unit effective as of midnight of 

December 31 of a specified calendar 

year, which date must be at least 4 years 

after December 31 of the year of the 

unit’s entry into the TR NOX Annual 

Trading Program under § 97.441(h). The 

request shall be in a format prescribed 

by the Administrator and shall be 

submitted no later than 90 days before 

the requested effective date of 

withdrawal. 

(b) Conditions for withdrawal. Before 

a TR NOX Annual opt-in unit covered 

by the request to withdraw may 

withdraw from the TR NOX Annual 

Trading Program, the following 

conditions must be met: 

(1) For the control period ending on 

the date on which the withdrawal is to 

be effective, the source that includes the 

TR NOX Annual opt-in unit must meet 

the requirement to hold TR NOX Annual 

allowances under §§ 97.424 and 97.425 

and cannot have any excess emissions. 

(2) After the requirement under 

paragraph (b)(1) of this section is met, 

the Administrator will deduct from the 

compliance account of the source that 

includes the TR NOX Annual opt-in unit 

TR NOX Annual allowances equal in 

amount to and allocated for the same or 

a prior control period as any TR NOX

Annual allowances allocated to the TR 

NOX Annual opt-in unit under § 97.444 

for any control period after the date on 

which the withdrawal is to be effective. 

If there are no other TR NOX Annual 

units at the source, the Administrator 

will close the compliance account, and 

the owners and operators of the TR NOX

Annual opt-in unit may submit a TR 

NOX Annual allowance transfer for any 

remaining TR NOX Annual allowances 

to another Allowance Management 

System account in accordance with 

§§ 97.422 and 97.423. 

(c) Approving withdrawal. (1) After 

the requirements for withdrawal under 

paragraphs (a) and (b) of this section are 

met (including deduction of the full 

amount of TR NOX Annual allowances 

required), the Administrator will issue a 

written approval of the request to 

withdraw, which will become effective 

as of midnight on December 31 of the 

calendar year for which the withdrawal 

was requested. The unit covered by the 

request shall continue to be a TR NOX

Annual opt-in unit until the effective 

date of the withdrawal and shall comply 

with all requirements under the TR NOX


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Annual Trading Program concerning 

any control periods for which the unit 

is a TR NOX Annual opt-in unit, even 

if such requirements arise or must be 

complied with after the withdrawal 

takes effect. 

(2) If the requirements for withdrawal 

under paragraphs (a) and (b) of this 

section are not met, the Administrator 

will issue a written disapproval of the 

request to withdraw. The unit covered 

by the request shall continue to be a TR 

NOX Annual opt-in unit. 

(d) Reapplication upon failure to meet 

conditions of withdrawal. If the 

Administrator disapproves the request 

to withdraw, the designated 

representative of the unit may submit 

another request to withdraw in 

accordance with paragraphs (a) and (b) 

of this section. 

(e) Ability to reapply to the TR NOX

Annual Trading Program. Once a TR 

NOX Annual opt-in unit withdraws from 

the TR NOX Annual Trading Program, 

the designated representative may not 

submit another opt-in application under 

§ 97.441 for such unit before the date 

that is 4 years after the date on which 

the withdrawal became effective. 

§ 97.443 Change in regulatory status. 

(a) Notification. If a TR NOX Annual 

opt-in unit becomes a TR NOX Annual 

unit under § 97.404, then the designated 

representative of the unit shall notify 

the Administrator in writing of such 

change in the TR NOX Annual opt-in 

unit’s regulatory status, within 30 days 

of such change. 

(b) Administrator’s actions. (1) If a TR 

NOX Annual opt-in unit becomes a TR 

NOX Annual unit under § 97.404, the 

Administrator will deduct, from the 

compliance account of the source that 

includes the TR NOX Annual opt-in unit 

that becomes a TR NOX Annual unit 

under § 97.404, TR NOX Annual 

allowances equal in amount to and 

allocated for the same or a prior control 

period as: 

(i) Any TR NOX Annual allowances 

allocated to the TR NOX Annual opt-in 

unit under § 97.444 for any control 

period starting after the date on which 

the TR NOX Annual opt-in unit becomes 

a TR NOX Annual unit under § 97.404; 

and 

(ii) If the date on which the TR NOX

Annual opt-in unit becomes a TR NOX

Annual unit under § 97.404 is not 

December 31, the TR NOX Annual 

allowances allocated to the TR NOX

Annual opt-in unit under § 97.444 for 

the control period that includes the date 

on which the TR NOX Annual opt-in 

unit becomes a TR NOX Annual unit 

under § 97.404— 

(A) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

NOX Annual opt-in unit becomes a TR 

NOX Annual unit under § 97.404, 

divided by the total number of days in 

the control period, and 

(B) Rounded to the nearest allowance. 

(2) The designated representative 

shall ensure that the compliance 

account of the source that includes the 

TR NOX Annual opt-in unit that 

becomes a TR NOX Annual unit under 

§ 97.404 contains the TR NOX Annual 

allowances necessary for completion of 

the deduction under paragraph (b)(1) of 

this section. 

(3)(i) For control periods starting after 

the date on which the TR NOX Annual 

opt-in unit becomes a TR NOX Annual 

unit under § 97.404, the TR NOX Annual 

opt-in unit will be allocated TR NOX

Annual allowances in accordance with 

§ 97.412. 

(ii) If the date on which the TR NOX

Annual opt-in unit becomes a TR NOX

Annual unit under § 97.404 is not 

December 31, the following amount of 

TR NOX Annual allowances will be 

allocated to the TR NOX Annual opt-in 

unit (as a TR NOX Annual unit) in 

accordance with § 97.412 for the control 

period that includes the date on which 

the TR NOX Annual opt-in unit becomes 

a TR NOX Annual unit under § 97.404: 

(A) The amount of TR NOX Annual 

allowances otherwise allocated to the 

TR NOX Annual opt-in unit (as a TR 

NOX Annual unit) in accordance with 

§ 97.412 for the control period; 

(B) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

NOX Annual opt-in unit becomes a TR 

NOX Annual unit under § 97.404, 

divided by the total number of days in 

the control period; and (C) Rounded to 

the nearest allowance. 

§ 97.444 TR NOX Annual allowance 

allocations to TR NOX Annual opt-in units. 

(a) Timing requirements. (1) When the 

TR opt-in application is approved for a 

unit under § 97.441(g), the 

Administrator will issue TR NOX

Annual allowances and allocate them to 

the unit for the control period in which 

the unit enters the TR NOX Annual 

Trading Program under § 97.441(h), in 

accordance with paragraph (b) of this 

section. 

(2) By no later than October 31 of the 

control period after the control period in 

which a TR NOX Annual opt-in unit 

enters the TR NOX Annual Trading 

Program under § 97.441(h) and October 

31 of each year thereafter, the 

Administrator will issue TR NOX

Annual allowances and allocate them to 

the TR NOX Annual opt-in unit for the 

control period that includes such 

allocation deadline and in which the 

unit is a TR NOX Annual opt-in unit, in 

accordance with paragraph (b) of this 

section. 

(b) Calculation of allocation. For each 

control period for which a TR NOX

Annual opt-in unit is to be allocated TR 

NOX Annual allowances, the 

Administrator will issue and allocate TR 

NOX Annual allowances in accordance 

with the following procedures: 

(1) The heat input (in mmBtu) used 

for calculating the TR NOX Annual 

allowance allocation will be the lesser 

of: 

(i) The TR NOX Annual opt-in unit’s 

baseline heat input determined under 

§ 97.441(g); or 

(ii) The TR NOX Annual opt-in unit’s 

heat input, as determined in accordance 

with §§ 97.430 through 97.435, for the 

immediately prior control period, 

except when the allocation is being 

calculated for the control period in 

which the TR NOX Annual opt-in unit 

enters the TR NOX Annual Trading 

Program under § 97.441(h). 

(2) The NOX emission rate (in lb/ 

mmBtu) used for calculating TR NOX

Annual allowance allocations will be 

the lesser of: 

(i) The TR NOX Annual opt-in unit’s 

baseline NOX emission rate (in lb/ 

mmBtu) determined under § 97.441(g) 

and multiplied by 70 percent; or 

(ii) The most stringent State or 

Federal NOX emissions limitation 

applicable to the TR NOX Annual optin unit at any time during the control 

period for which TR NOX Annual 

allowances are to be allocated. 

(3) The Administrator will issue TR 

NOX Annual allowances and allocate 

them to the TR NOX Annual opt-in unit 

in an amount equaling the heat input 

under paragraph (b)(1) of this section, 

multiplied by the NOX emission rate 

under paragraph (b)(2) of this section, 

divided by 2,000 lb/ton, and rounded to 

the nearest allowance. 

(c) Recordation. (1) The Administrator 

will record, in the compliance account 

of the source that includes the TR NOX

Annual opt-in unit, the TR NOX Annual 

allowances allocated to the TR NOX

Annual opt-in unit under paragraph 

(a)(1) of this section. 

(2) By December 1 of the control 

period after the control period in which 

a TR NOX Annual opt-in unit enters the 

TR NOX Annual Trading Program under 

§ 97.441(h) and December 1 of each year 

thereafter, the Administrator will 

record, in the compliance account of the 

source that includes the TR NOX

Annual opt-in unit, the TR NOX Annual 

allowances allocated to the TR NOX


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Annual opt-in unit under paragraph 

(a)(2) of this section. 

36. Part 97 is amended by adding 

subpart BBBBB to read as follows: 

Subpart BBBBB—TR NOX Ozone Season 

Trading Program 

Sec. 

97.501 Purpose. 

97.502 Definitions. 

97.503 Measurements, abbreviations, and 

acronyms. 

97.504 Applicability. 

97.505 Retired unit exemption. 

97.506 Standard requirements. 

97.507 Computation of time. 

97.508 Administrative appeal procedures. 

97.509 [Reserved] 

97.510 State NOX Ozone Season trading 

budgets, new-unit set-asides, and 

variability limits. 

97.511 Timing requirements for TR NOX

Ozone Season allowance allocations. 

97.512 TR NOX Ozone Season allowance 

allocations for new units. 

97.513 Authorization of designated 

representative and alternate designated 

representative. 

97.514 Responsibilities of designated 

representative and alternate designated 

representative. 

97.515 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.516 Certificate of representation. 

97.517 Objections concerning designated 

representative and alternate designated 

representative. 

97.518 Delegation by designated 

representative and alternate designated 

representative. 

97.519 [Reserved] 

97.520 Establishment of Allowance 

Management System accounts. 

97.521 Recordation of TR NOX Ozone 

Season allowance allocations. 

97.522 Submission of TR NOX Ozone 

Season allowance transfers. 

97.523 Recordation of TR NOX Ozone 

Season allowance transfers. 

97.524 Compliance with TR NOX Ozone 

Season emissions limitation. 

97.525 Compliance with TR NOX Ozone 

Season assurance provisions. 

97.526 Banking. 

97.527 Account error. 

97.528 Administrator’s action on 

submissions. 

97.529 [Reserved] 

97.530 General monitoring, recordkeeping, 

and reporting requirements. 

97.531 Initial monitoring system 

certification and recertification 

procedures. 

97.532 Monitoring system out-of-control 

periods. 

97.533 Notifications concerning 

monitoring. 

97.534 Recordkeeping and reporting. 

97.535 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

97.540 General requirements for TR NOX

Ozone Season opt-in units. 

97.541 Opt-in process. 

97.542 Withdrawal of TR NOX Ozone 

Season opt-in unit from TR NOX Ozone 

Season Trading Program. 

97.543 Change in regulatory status. 

97.544 TR NOX Ozone Season allowance 

allocations to TR NOX Ozone Season optin units. 

Subpart BBBBB—TR NOX Ozone 

Season Trading Program 

§ 97.501 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) NOX Ozone Season 

Trading Program, under section 110 of 

the Clean Air Act and § 52.37(b) of this 

chapter, as a means of mitigating 

interstate transport of fine particulates 

and nitrogen oxides. 

§ 97.502 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor) of the United 

States Environmental Protection 

Agency, the Administrator’s duly 

authorized representative under this 

subpart. 

Allocate or allocation means, with 

regard to TR NOX Ozone Season 

allowances, the determination by the 

Administrator of the amount of such TR 

NOX Ozone Season allowances to be 

initially credited to a TR NOX Ozone 

Season source or a new unit set-aside. 

Allowable NOX emission rate means, 

with regard to a unit, the NOX emission 

rate limit that is applicable to the unit 

and covers the longest averaging period 

not exceeding one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR NOX

Ozone Season allowances under the TR 

NOX Ozone Season Trading Program. 

Such allowances are allocated, held, 

deducted, or transferred only as whole 

allowances. The Allowance 

Management System is a component of 

the CAMD Business System, which is 

the system used by the Administrator to 

handle TR NOX Ozone Season 

allowances and data related to NOX

emissions. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

NOX Ozone Season allowances. 

Allowance transfer deadline means, 

for a control period, midnight of 

December 1 (if it is a business day), or 

midnight of the first business day 

thereafter (if December 1 is not a 

business day), immediately after such 

control period and is the deadline by 

which a TR NOX Ozone Season 

allowance transfer must be submitted 

for recordation in a TR NOX Ozone 

Season source’s compliance account in 

order to be available for use in 

complying with the source’s TR NOX

Ozone Season emissions limitation for 

such control period in accordance with 

§ 97.524. 

Alternate designated representative 

means, for a TR NOX Ozone Season 

source and each TR NOX Ozone Season 

unit at the source, the natural person 

who is authorized by the owners and 

operators of the source and all such 

units at the source, in accordance with 

this subpart, to act on behalf of the 

designated representative in matters 

pertaining to the TR NOX Ozone Season 

Trading Program. If the TR NOX Ozone 

Season source is also subject to the Acid 

Rain Program, TR NOX Annual Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 2 Trading 

Program, then this natural person shall 

be the same natural person as the 

alternate designated representative as 

defined in § 72.2 of this chapter, 

§ 97.402, § 97.602, or § 97.702 

respectively. 

Authorized account representative 

means, with regard to a general account, 

the natural person who is authorized, in 

accordance with this subpart, to transfer 

and otherwise dispose of TR NOX Ozone 

Season allowances held in the general 

account and, with regard to a TR NOX

Ozone Season source’s compliance 

account, the designated representative 

of the source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 


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(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

Certifying official means a natural 

person who is: 

(1) For a corporation, a president, 

secretary, treasurer, or vice-president or 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy or 

decision-making functions for the 

corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Coal-fired means combusting any 

amount of coal or coal-derived fuel, 

alone or in combination with any 

amount of any other fuel, during 1990 

or any year thereafter. 

Cogeneration system means an 

integrated group, at a source, of 

equipment (including a boiler, or 

combustion turbine, and a steam turbine 

generator) designed to produce useful 

thermal energy for industrial, 

commercial, heating, or cooling 

purposes and electricity through the 

sequential use of energy. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine— 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing during the later of 1990 

or the 12-month period starting on the 

date that the unit first produces 

electricity and during each calendar 

year after the later of 1990 or the 

calendar year in which the unit first 

produces electricity— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle unit, useful 

power not less than 45 percent of total 

energy input; 

(3) Provided that the total energy 

input under paragraphs (2)(i)(B) and 

(2)(ii) of this definition shall equal the 

unit’s total energy input from all fuel, 

except biomass if the unit is a boiler; 

and 

(4) Provided that, if a topping-cycle 

unit is operated as part of a cogeneration 

system during a calendar year and the 

cogeneration system meets on a systemwide basis the requirement in paragraph 

(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such 

requirement during that calendar year. 

Combustion turbine means an 

enclosed device comprising: 

(1) If the device is simple cycle, a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the device is combined cycle, 

the equipment described in paragraph 

(1) of this definition and any associated 

duct burner, heat recovery steam 

generator, and steam turbine. 

Commence commercial operation 

means, with regard to a unit: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 97.505. 

(i) For a unit that is a TR NOX Ozone 

Season unit under § 97.504 on the later 

of November 15, 1990 or the date the 

unit commences commercial operation 

as defined in the introductory text of 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit that is a TR NOX Ozone 

Season unit under § 97.504 on the later 

of November 15, 1990 or the date the 

unit commences commercial operation 

as defined in the introductory text of 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source, such date shall remain the 

replaced unit’s date of commencement 

of commercial operation, and the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 97.505, for a unit that is not a TR 

NOX Ozone Season unit under § 97.504 

on the later of November 15, 1990 or the 

date the unit commences commercial 

operation as defined in introductory text 

of paragraph (1) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a TR NOX

Ozone Season unit under § 97.504. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that subsequently undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source), 

such date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that is subsequently replaced by a 

unit at the same source, such date shall 

remain the replaced unit’s date of 

commencement of commercial 

operation, and the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

Commence operation means, with 

regard to a unit: 

(1) To have begun any mechanical, 

chemical, or electronic process, 

including start-up of the unit’s 

combustion chamber. 

(2) For a unit that undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source) 


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after the date the unit commences 

operation as defined in paragraph (1) of 

this definition, such date shall remain 

the date of commencement of operation 

of the unit, which shall continue to be 

treated as the same unit. 

(3) For a unit that is replaced by a unit 

at the same source after the date the unit 

commences operation as defined in 

paragraph (1) of this definition, such 

date shall remain the replaced unit’s 

date of commencement of operation, 

and the replacement unit shall be 

treated as a separate unit with a separate 

date for commencement of operation as 

defined in paragraph (1), (2), or (3) of 

this definition as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR NOX Ozone 

Season source under this subpart, in 

which any TR NOX Ozone Season 

allowance allocations for the TR NOX

Ozone Season units at the source are 

recorded and in which are held any TR 

NOX Ozone Season allowances available 

for use for a control period in complying 

with the source’s TR NOX Ozone Season 

emissions limitation in accordance with 

§ 97.524 and the TR NOX Ozone Season 

assurance provisions in accordance with 

§ 97.525. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of NOX emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.530 

through 97.535. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A NOX concentration monitoring 

system, consisting of a NOX pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of NOX

emissions, in parts per million (ppm); 

(3) A NOX emission rate (or NOXdiluent) monitoring system, consisting 

of a NOX pollutant concentration 

monitor, a diluent gas (CO2 or O2) 

monitor, and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of NOX concentration, in parts 

per million (ppm), diluent gas 

concentration, in percent CO2 or O2, and 

NOX emission rate, in pounds per 

million British thermal units (lb/ 

mmBtu); 

(4) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(5) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(6) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting May 1 of a calendar year, except 

as provided in § 97.506(c)(3), and 

ending on September 30 of the same 

year, inclusive. 

Designated representative means, for 

a TR NOX Ozone Season source and 

each TR NOX Ozone Season unit at the 

source, the natural person who is 

authorized by the owners and operators 

of the source and all such units at the 

source, in accordance with this subpart, 

to represent and legally bind each 

owner and operator in matters 

pertaining to the TR NOX Ozone Season 

Trading Program. If the TR NOX Ozone 

Season source is also subject to the Acid 

Rain Program, TR NOX Annual Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 2 Trading 

Program, then this natural person shall 

be the same natural person as the 

designated representative, as defined in 

§ 72.2 of this chapter, § 97.402, § 97.602, 

or § 97.702 respectively. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart. 

Excess emissions means any ton of 

NOX emitted from the TR NOX Ozone 

Season units at a TR NOX Ozone Season 

source during a control period that 

exceeds the TR NOX Ozone Season 

emissions limitation for the source. 

Fossil fuel means— 

(1) Natural gas, petroleum, coal, or 

any form of solid, liquid, or gaseous fuel 

derived from such material; or 

(2) For purposes of applying 

§§ 97.504(b)(2)(i)(B), 97.504(b)(2)(ii)(B), 

and 97.504(b)(2)(iii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 1990 or any calendar year 

thereafter. 

Fuel oil means any petroleum-based 

fuel (including diesel fuel or petroleum 

derivatives such as oil tar) and any 

recycled or blended petroleum products 

or petroleum by-products used as a fuel 

whether in a liquid, solid, or gaseous 

state. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a unit, electricity made 

available for use, including any such 

electricity used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Heat input means, with regard to a 

unit for a specified period of time, the 

product (in mmBtu/time) of the gross 

calorific value of the fuel (in mmBtu/lb) 

multiplied by the fuel feed rate into a 

combustion device (in lb of fuel/time), 

as measured, recorded, and reported to 

the Administrator by the designated 

representative and as modified by the 

Administrator in accordance with this 

subpart and excluding the heat derived 

from preheated combustion air, 

recirculated flue gases, or exhaust. 

Heat input rate means the amount of 

heat input (in mmBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 


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(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means 

the maximum amount of fuel per hour 

(in Btu/hr) that a unit is capable of 

combusting on a steady state basis as of 

the initial installation of the unit as 

specified by the manufacturer of the 

unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as of such 

installation as specified by the 

manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as of such completion as 

specified by the person conducting the 

physical change. 

Newly affected TR NOX Ozone Season 

unit means a unit that was not a TR NOX

Ozone Season unit when it began 

operating but that thereafter becomes a 

TR NOX Ozone Season unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means any person who 

operates, controls, or supervises a TR 

NOX Ozone Season unit or a TR NOX

Ozone Season source and shall include, 

but not be limited to, any holding 

company, utility system, or plant 

manager of such a unit or source. 

Owner means, with regard to a TR 

NOX Ozone Season source or a TR NOX

Ozone Season unit at a source 

respectively, any of the following 

persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR NOX

Ozone Season unit at the source or the 

TR NOX Ozone Season unit; 

(2) Any holder of a leasehold interest 

in a TR NOX Ozone Season unit at the 

source or the TR NOX Ozone Season 

unit, provided that, unless expressly 

provided for in a leasehold agreement, 

‘‘owner’’ shall not include a passive 

lessor, or a person who has an equitable 

interest through such lessor, whose 

rental payments are not based (either 

directly or indirectly) on the revenues or 

income from such TR NOX Ozone 

Season unit; 

(3) Any purchaser of power from a TR 

NOX Ozone Season unit at the source or 

the TR NOX Ozone Season unit under a 

life-of-the-unit, firm power contractual 

arrangement; 

(4) Provided that, for purposes of 

applying the TR NOX Ozone Season 

assurance provisions in §§ 97.506(c)(2) 

and 97.525, if one or more owners (as 

defined in paragraphs (1) through (3) of 

this definition) of one or more TR NOX

Ozone Season units in a State are 

wholly owned by another, common 

owner, all such owners shall be treated 

collectively as a single owner in the 

State. 

Owner’s assurance level means: 

(1) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.506(c)(2)(iii)(A) and not as 

described in § 97.506(c)(2)(iii)(B), the 

owner’s share of the State NOX Ozone 

Season trading budget with the one-year 

variability limit for the State for such 

control period; or 

(2) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.506(c)(2)(iii)(B), the owner’s share 

of the State NOX Ozone Season trading 

budget with the three-year variability 

limit for the State for such control 

period. 

Owner’s share means: 

(1) With regard to a total amount of 

NOX emissions from all TR NOX Ozone 

Season units in a State during a control 

period, the total tonnage of NOX

emissions during such control period 

from all of the owner’s TR NOX Ozone 

Season units in the State; 

(2) With regard to a State NOX Ozone 

Season trading budget with a one-year 

variability limit for a control period, the 

amount (rounded to the nearest 

allowance) equal to the total amount of 

TR NOX Ozone Season allowances 

allocated for such control period to all 

of the owner’s TR NOX Ozone Season 

units in the State, multiplied by the sum 

of the State NOX Ozone Season trading 

budget under § 97.510(a) and the State’s 

one-year variability limit under 

§ 97.510(b) and divided by such State 

NOX Ozone Season trading budget; 

(3) With regard to a State NOX Ozone 

Season trading budget with a three-year 

variability limit for a control period, the 

amount (rounded to the nearest 

allowance) equal to the total amount of 

TR NOX Ozone Season allowances 

allocated for such control period to all 

of the owner’s TR NOX Ozone Season 

units in the State, multiplied by the sum 

of the State NOX Ozone Season trading 

budget under § 97.510(a) and the State’s 

three-year variability limit under 

§ 97.510(b) and divided by such State 

NOX Ozone Season trading budget; 

(4) Provided that, in the case of a unit 

with more than one owner, the amount 

of tonnage of NOX emissions and of TR 

NOX Ozone Season allowances allocated 

for a control period, with regard to such 

unit, used in determining each owner’s 

share shall be the amount (rounded to 

the nearest ton and the nearest 

allowance) equal to the unit’s NOX

emissions and allocation of such 

allowances, respectively, for such 

control period multiplied by the 

percentage of ownership in the unit that 

the owner’s legal, equitable, leasehold, 

or contractual reservation or entitlement 

in the unit comprises as of September 

30 of such control period; 

(5) Provided that, where two or more 

units emit through a common stack that 

is the monitoring location from which 

NOX mass emissions are reported for a 

control period for a year, the amount of 

tonnage of each unit’s NOX emissions 

used in determining each owner’s share 

for such control period shall be: 

(i) The amount (rounded to the 

nearest ton) of NOX emissions reported 

at the common stack multiplied by the 

quotient of such unit’s heat input for 

such control period divided by the total 

heat input reported from the common 

stack for such control period; 

(ii) An amount determined in 

accordance with a methodology that the 

Administrator determines is consistent 

with the purposes of this definition and 

whose adverse effect (if any) the 

Administrator determines will be de 

minimis; or 

(iii) An amount approved by the 

Administrator in response to a petition 

for an alternative requirement submitted 

in accordance with § 97.535; and 

(6) Provided that, in the case of a unit 

that operates during, but is allocated no 

TR NOX Ozone Season allowances for, 

a control period, the unit shall be 

treated, solely for purposes of this 

definition, as being allocated an amount 

(rounded to the nearest allowance) of 

TR NOX Ozone Season allowances for 

such control period equal to the lesser 

of— 


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(i) The unit’s allowable NOX emission 

rate (in lb per MWe) applicable to such 

control period, multiplied by a capacity 

factor of 0.89 (if the unit is a coal-fired 

boiler), 0.22 (if the unit is a simple 

combustion turbine), or 0.72 (if the unit 

is a combined cycle turbine), multiplied 

by the unit’s maximum hourly load as 

reported in accordance with this subpart 

and by 3,672 hours/control period, and 

divided by 2,000 lb/ton; or 

(ii) For a unit listed in appendix A to 

this subpart, the sum of the unit’s NOX

emissions in the control period in the 

last three years during which the unit 

operated during the control period, 

divided by three. 

Permanently retired means, with 

regard to a unit, a unit that is 

unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Potential electrical output capacity 

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/ 

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR NOX Ozone 

Season allowances, the moving of TR 

NOX Ozone Season allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) For a topping-cycle unit, the use 

of reject heat from electricity production 

in a useful thermal energy application 

or process; or 

(2) For a bottoming-cycle unit, the use 

of reject heat from useful thermal energy 

application or process in electricity 

production. 

Serial number means, for a TR NOX

Ozone Season allowance, the unique 

identification number assigned to each 

TR NOX Ozone Season allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States or the 

District of Columbia that is subject to 

the TR NOX Ozone Season Trading 

Program pursuant to § 52.37(b) of this 

chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline shall 

be determined by the date of dispatch, 

transmission, or mailing and not the 

date of receipt. 

Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means total energy 

of all forms supplied to a unit, 

excluding energy produced by the unit. 

Each form of energy supplied shall be 

measured by the lower heating value of 

that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55 (W + 9H) 

Where: 

LHV = lower heating value of the form of 

energy in Btu/lb, 

HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means the sum of 

useful power and useful thermal energy 

produced by the unit. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with subpart AAAAA of this 

part and 52.37(a) of this chapter, as a 

means of mitigating interstate transport 

of fine particulates and NOX.

TR NOX Ozone Season allowance 

means a limited authorization issued 

and allocated by the Administrator 

under this subpart to emit one ton of 

NOX during a control period of the 

specified calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the TR 

NOX Ozone Season Program. 

TR NOX Ozone Season allowance 

deduction or deduct TR NOX Ozone 

Season allowances means the 

permanent withdrawal of TR NOX

Ozone Season allowances by the 

Administrator from a compliance 

account, e.g., in order to account for 

compliance with the TR NOX Ozone 

Season emissions limitation or 

assurance provisions. 

TR NOX Ozone Season allowances 

held or hold TR NOX Ozone Season 

allowances means the TR NOX Ozone 

Season allowances treated as included 

in an Allowance Management System 

account as of a specified point in time 

because at that time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR NOX Ozone Season 

allowance transfer in accordance with 

this subpart; and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR NOX Ozone 

Season allowance transfer in accordance 

with this subpart. 

TR NOX Ozone Season emissions 

limitation means, for a TR NOX Ozone 

Season source, the tonnage of NOX

emissions authorized in a control period 

by the TR NOX Ozone Season 

allowances available for deduction for 

the source under § 97.524(a) for such 

control period. 

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established by the 

Administrator in accordance with this 

subpart and 52.37(b) of this chapter, as 

a means of mitigating interstate 

transport of ozone and NOX.

TR NOX Ozone Season source means 

a source that includes one or more TR 

NOX Ozone Season units. 


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TR NOX Ozone Season unit means a 

unit that is subject to the TR NOX Ozone 

Season Trading Program under § 97.504. 

TR SO2 Group 1 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with subpart CCCCC of this 

part and 52.38(b) of this chapter, as a 

means of mitigating interstate transport 

of fine particulates and SO2.

TR SO2 Group 2 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with subpart DDDDD of this 

part and 52.38(c) of this chapter, as a 

means of mitigating interstate transport 

of fine particulates and SO2.

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired 

combustion turbine, or other stationary, 

fossil-fuel-fired combustion device. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means electricity or 

mechanical energy that a unit makes 

available for use, excluding any such 

energy used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.503 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.504 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State shall 

be TR NOX Ozone Season units, and any 

source that includes one or more such 

units shall be a TR NOX Ozone Season 

source, subject to the requirements of 

this subpart: Any stationary, fossil-fuelfired boiler or stationary, fossil-fuelfired combustion turbine serving at any 

time, since the later of November 15, 

1990 or the start-up of the unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(2) If a stationary boiler or stationary 

combustion turbine that, under 

paragraph (a)(1) of this section, is not a 

TR NOX Ozone Season unit begins to 

combust fossil fuel or to serve a 

generator with nameplate capacity of 

more than 25 MWe producing electricity 

for sale, the unit shall become a TR NOX

Ozone Season unit as provided in 

paragraph (a)(1) of this section on the 

first date on which it both combusts 

fossil fuel and serves such generator. 

(b) Any unit in a State that otherwise 

is a TR NOX Ozone Season unit under 

paragraph (a) of this section and that 

meets the requirements set forth in 

paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) 

of this section shall not be a TR NOX

Ozone Season unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

during the later of 1990 or the 12-month 

period starting on the date the unit first 

produces electricity and continuing to 

qualify as a cogeneration unit; and 

(B) Not serving at any time, since the 

later of November 15, 1990 or the startup of the unit’s combustion chamber, a 

generator with nameplate capacity of 

more than 25 MWe supplying in any 

calendar year more than one-third of the 

unit’s potential electric output capacity 

or 219,000 MWh, whichever is greater, 

to any utility power distribution system 

for sale. 

(ii) If a unit qualifies as a cogeneration 

unit during the later of 1990 or the 12- 

month period starting on the date the 

unit first produces electricity and meets 

the requirements of paragraphs (b)(1)(i) 

of this section for at least one calendar 

year, but subsequently no longer meets 

such qualification and requirements, the 

unit shall become a TR NOX Ozone 

Season unit starting on the earlier of 

January 1 after the first calendar year 

during which the unit first no longer 

qualifies as a cogeneration unit or 

January 1 after the first calendar year 

during which the unit no longer meets 

the requirements of paragraph 

(b)(1)(i)(B) of this section. 

(2)(i) Any unit commencing operation 

before January 1, 1985: 

(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average Ozone Season 

fuel consumption of fossil fuel for 1985– 

1987 less than 20 percent (on a Btu 

basis) and an average Ozone Season fuel 

consumption of fossil fuel for any 3 

consecutive calendar years after 1990 

less than 20 percent (on a Btu basis). 

(ii) Any unit commencing operation 

on or after January 1, 1985: 

(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average Ozone Season 

fuel consumption of fossil fuel for the 

first 3 calendar years of operation less 

than 20 percent (on a Btu basis) and an 

average Ozone Season fuel consumption 

of fossil fuel for any 3 consecutive 

calendar years after 1990 less than 20 

percent (on a Btu basis). 

(iii) If a unit qualifies as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and meets the requirements 

of paragraph (b)(2)(i) or (ii) of this 

section for at least 3 consecutive 

calendar years, but subsequently no 

longer meets such qualification and 

requirements, the unit shall become a 

TR NOX Ozone Season unit starting on 

the earlier of January 1 after the first 

calendar year during which the unit first 

no longer qualifies as a solid waste 

incineration unit or January 1 after the 

first 3 consecutive calendar years after 

1990 for which the unit has an average 

Ozone Season fuel consumption of 

fossil fuel of 20 percent or more. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 

may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR NOX Ozone 

Season Trading Program to the unit or 

other equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 


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equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the petition shall 

include the following certification 

statement, signed by the certifying 

official: ‘‘I am authorized to make this 

submission on behalf of the owners and 

operators of the unit or other equipment 

for which the submission is made. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) Response. The Administrator will 

issue a written response to the petition 

and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR NOX Ozone 

Season Trading Program to the unit or 

other equipment shall be binding on any 

permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.505 Retired unit exemption. 

(a)(1) Any TR NOX Ozone Season unit 

that is permanently retired and is not a 

TR NOX Ozone Season opt-in unit shall 

be exempt from § 97.506(b) and (c)(1), 

§ 97.524, and §§ 97.530 through 97.535. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR NOX

Ozone Season unit is permanently 

retired. Within 30 days of the unit’s 

permanent retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any NOX, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

NOX Ozone Season Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 

§ 97.506 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.513 through 97.518. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each TR 

NOX Ozone Season source and each TR 

NOX Ozone Season unit at the source 

shall comply with the monitoring, 

reporting, and recordkeeping 

requirements of §§ 97.530 through 

97.535. 

(2) The emissions data determined in 

accordance with §§ 97.530 through 

97.535 shall be used to calculate 

allocations of TR NOX Ozone Season 

allowances under §§ 97.511(a)(2) and (b) 

and 97.512 and to determine 

compliance with the TR NOX Ozone 

Season emissions limitation and 

assurance provisions under paragraph 

(c) of this section, provided that, for 

each monitoring location from which 

mass emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.530 through 97.535 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) NOX emissions requirements—(1) 

TR NOX Ozone Season emissions 

limitation. (i) As of the allowance 

transfer deadline for a control period, 

the owners and operators of each TR 

NOX Ozone Season source and each TR 

NOX Ozone Season unit at the source 

shall hold, in the source’s compliance 

account, TR NOX Ozone Season 

allowances available for deduction for 

such control period under § 97.524(a) in 

an amount not less than the tons of total 

NOX emissions for such control period 

from all TR NOX Ozone Season units at 

the source. 

(ii) If a TR NOX Ozone Season source 

emits NOX during any control period in 

excess of the TR NOX Ozone Season 

emissions limitation set forth in 

paragraph (c)(1)(i) of this section, then: 

(A) The owners and operators of the 

source and each TR NOX Ozone Season 

unit at the source shall hold the TR NOX

Ozone Season allowances required for 

deduction under § 97.524(d) and pay 

any fine, penalty, or assessment or 

comply with any other remedy imposed, 

for the same violations, under the Clean 

Air Act; and 

(B) Each ton of such excess emissions 

and each day of such control period 

shall constitute a separate violation of 

this subpart and the Clean Air Act. 

(2) TR NOX Ozone Season assurance 

provisions. (i) If the total amount of 

NOX emissions from all TR NOX Ozone 

Season units in a State during a control 

period in 2014 or any year thereafter 

exceeds the State assurance level as 

described in paragraph (c)(2)(iii) of this 

section, then each owner whose share of 

such NOX emissions during such 

control period exceeds the owner’s 

assurance level for the State and such 

control period shall hold, in a 

compliance account designated by the 

owner in accordance with 

§ 97.525(b)(4)(ii), TR NOX Ozone Season 

allowances available for deduction for 

such control period under § 97.525(a) in 

an amount equal to the product, as 

determined by the Administrator in 

accordance with § 97.525(b), of 

multiplying— 

(A) The quotient (rounded to the 

nearest whole number) of the amount by 

which the owner’s share of such NOX

emissions exceeds the owner’s 

assurance level divided by the sum of 

the amounts, determined for all such 

owners, by which each owner’s share of 

such NOX emissions exceeds that 

owner’s assurance level; and 

(B) The amount by which total NOX

emissions for all TR NOX Ozone Season 


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units in the State for such control period 

exceed the State assurance level as 

determined in accordance with 

paragraph (c)(2)(iii) of this section. 

(ii) The owner shall hold the TR NOX

Ozone Season allowances required 

under paragraph (c)(2)(i) of this section, 

as of midnight of August 1 (if it is a 

business day), or midnight of the first 

business day thereafter (if August 1 is 

not a business day), immediately after 

such control period. 

(iii) The total amount of NOX

emissions from all TR NOX Ozone 

Season units in a State during a control 

period in 2014 or any year thereafter 

exceeds the State assurance level: 

(A) If such total amount of NOX

emissions exceeds the sum, for such 

control period, of the State NOX Ozone 

Season trading budget and the State’s 

one-year variability limit under 

§ 97.510(b); or 

(B) If, with regard to a control period 

in 2016 or any year thereafter, the sum, 

divided by three, of such total amount 

of NOX emissions and the total amounts 

of NOX emissions from all TR NOX

Ozone Season units in the State during 

the control periods in the immediately 

preceding two years exceeds the sum, 

for such control period, of the State NOX

Ozone Season trading budget and the 

State’s three-year variability limit under 

§ 97.510(b); 

(C) Provided that the amount by 

which such total amount of NOX

emissions exceeds the State assurance 

level shall be the greater of the amounts 

of the exceedance calculated under 

paragraph (c)(2)(iii)(A) of this section 

and under paragraph (c)(2)(iii)(B) of this 

section. 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if the 

total amount of NOX emissions from all 

TR NOX Ozone Season units in a State 

during a control period exceeds the 

State assurance level or if an owner’s 

share of total NOX emissions from the 

TR NOX Ozone Season units in a State 

during a control period exceeds the 

owner’s assurance level. 

(v) To the extent an owner fails to 

hold TR NOX Ozone Season allowances 

for a control period in accordance with 

paragraphs (c)(2)(i) and (ii) of this 

section, 

(A) The owner shall pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed under the 

Clean Air Act; and 

(B) Each TR NOX Ozone Season 

allowance that the owner fails to hold 

for a control period in accordance with 

paragraphs (c)(2)(i) and (ii) of this 

section and each day of such control 

period shall constitute a separate 

violation of this subpart and the Clean 

Air Act. 

(3) Compliance periods. A TR NOX

Ozone Season unit shall be subject to 

the requirements: 

(i) Under paragraph (c)(1) of this 

section for the control period starting on 

the later of September 1, 2012 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.530(b) and for each control period 

thereafter; and 

(ii) Under paragraph (c)(2) of this 

section for the control period starting on 

the later of September 1, 2014 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.530(b) and for each control period 

thereafter. 

(4) Vintage of deducted allowances. A 

TR NOX Ozone Season allowance shall 

not be deducted, for compliance with 

the requirements under paragraphs 

(c)(1) and (2) of this section, for a 

control period in a calendar year before 

the year for which the TR NOX Ozone 

Season allowance was allocated. 

(5) Allowance Management System 

requirements. Each TR NOX Ozone 

Season allowance shall be held in, 

deducted from, or transferred into, out 

of, or between Allowance Management 

System accounts in accordance with 

this subpart. 

(6) Limited authorization. (i) A TR 

NOX Ozone Season allowance is a 

limited authorization to emit one ton of 

NOX in accordance with the TR NOX

Ozone Season Trading Program. 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit such authorization to 

the extent the Administrator determines 

is necessary or appropriate to 

implement any provision of the Clean 

Air Act. 

(7) Property right. A TR NOX Ozone 

Season allowance does not constitute a 

property right. 

(d) Title V Permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of TR NOX Ozone Season 

allowances in accordance with this 

subpart. 

(2) A description of whether a unit is 

required to monitor and report NOX

emissions using a continuous emission 

monitoring system (under subpart H of 

part 75 of this chapter), an excepted 

monitoring system (under appendices D 

and E to part 75 of this chapter), a low 

mass emissions excepted monitoring 

methodology (under § 75.19 of this 

chapter), or an alternative monitoring 

system (under subpart E of part 75 of 

this chapter) in accordance with 

§§ 97.530 through 97.535 may be added 

to, or changed in, a title V permit using 

minor permit modification procedures 

in accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

the requirements applicable to the 

described monitoring and reporting (as 

added or changed, respectively) are 

already incorporated in such permit. 

This paragraph explicitly provides that 

the addition of, or change to, a unit’s 

description as described in the prior 

sentence is eligible for minor permit 

modification procedures in accordance 

with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. 

(1) Unless otherwise provided, the 

owners and operators of each TR NOX

Ozone Season source and each TR NOX

Ozone Season unit at the source shall 

keep on site at the source each of the 

following documents (in hardcopy or 

electronic format) for a period of 5 years 

from the date the document is created. 

This period may be extended for cause, 

at any time before the end of 5 years, in 

writing by the Administrator. 

(i) The certificate of representation 

under § 97.516 for the designated 

representative for the source and each 

TR NOX Ozone Season unit at the 

source and all documents that 

demonstrate the truth of the statements 

in the certificate of representation; 

provided that the certificate and 

documents shall be retained on site at 

the source beyond such 5-year period 

until such documents are superseded 

because of the submission of a new 

certificate of representation under 

§ 97.516 changing the designated 

representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the TR NOX Ozone 

Season Trading Program, including any 

monitoring plans and monitoring 

system certification and recertification 

applications. 

(2) The designated representative of a 

TR NOX Ozone Season source and each 

TR NOX Ozone Season unit at the 

source shall make all submissions 

required under the TR NOX Ozone 

Season Trading Program, including any 

submissions required for compliance 

with the TR NOX Ozone Season 

assurance provisions. This requirement 

does not change, create an exemption 

from, or or otherwise affect the 

responsible official submission 

requirements under a title V operating 


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permit program in parts 70 and 71 of 

this chapter. 

(f) Liability. (1) Any provision of the 

TR NOX Ozone Season Trading Program 

that applies to a TR NOX Ozone Season 

source or the designated representative 

of a TR NOX Ozone Season source shall 

also apply to the owners and operators 

of such source and of the TR NOX

Ozone Season units at the source. 

(2) Any provision of the TR NOX

Ozone Season Trading Program that 

applies to a TR NOX Ozone Season unit 

or the designated representative of a TR 

NOX Ozone Season unit shall also apply 

to the owners and operators of such 

unit. 

(g) Effect on other authorities. No 

provision of the TR NOX Ozone Season 

Trading Program or exemption under 

§ 97.505 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of a TR NOX Ozone 

Season source or TR NOX Ozone Season 

unit from compliance with any other 

provision of the applicable, approved 

State implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.507 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Ozone Season Trading Program, to begin 

on the occurrence of an act or event 

shall begin on the day the act or event 

occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Ozone Season Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

NOX Ozone Season Trading Program, 

falls on a weekend or a State or Federal 

holiday, the time period shall be 

extended to the next business day. 

§ 97.508 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR NOX Ozone Season Trading 

Program are set forth in part 78 of this 

chapter. 

§ 97.509 [Reserved] 

§ 97.510 State NOX Ozone Season trading 

budgets, new-unit set-asides, and variability 

limits. 

(a) The State NOX Ozone Season 

trading budgets and new-unit set-asides 

for allocations of TR NOX Ozone Season 

allowances for the control periods in 

2012 and thereafter are as follows: 

State 

NOX ozone season trading budget 

(tons)* 

New-unit set-aside 

(tons) 

For 2012 and 

thereafter 

For 2012 and 

thereafter 

Alabama ....................................................................................................................................................... 29,738 892 

Arkansas ...................................................................................................................................................... 16,660 500 

Connecticut .................................................................................................................................................. 1,315 39 

Delaware ...................................................................................................................................................... 2,450 74 

District of Columbia ..................................................................................................................................... 105 3 

Florida .......................................................................................................................................................... 56,939 1,708 

Georgia ........................................................................................................................................................ 32,144 964 

Illinois ........................................................................................................................................................... 23,570 707 

Indiana ......................................................................................................................................................... 49,987 1,500 

Kansas ......................................................................................................................................................... 21,433 643 

Kentucky ...................................................................................................................................................... 30,908 927 

Louisiana ...................................................................................................................................................... 21,220 637 

Maryland ...................................................................................................................................................... 7,232 217 

Michigan ....................................................................................................................................................... 28,253 848 

Mississippi .................................................................................................................................................... 16,530 496 

New Jersey .................................................................................................................................................. 5,269 158 

New York ..................................................................................................................................................... 11,090 333 

North Carolina .............................................................................................................................................. 23,539 706 

Ohio ............................................................................................................................................................. 40,661 1,220 

Oklahoma ..................................................................................................................................................... 37,087 1,113 

Pennsylvania ................................................................................................................................................ 48,271 1,448 

South Carolina ............................................................................................................................................. 15,222 457 

Tennessee ................................................................................................................................................... 11,575 347 

Texas ........................................................................................................................................................... 75,574 2,267 

Virginia ......................................................................................................................................................... 12,608 378 

West Virginia ................................................................................................................................................ 22,234 667 

Total ...................................................................................................................................................... 641,614 19,249 

* Without variability limits. 

(b) The States’ one-year and three-year 

variability limits for the State NOX

Ozone Season trading budgets for the 

control periods in 2014 and thereafter 

are as follows: 


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State 

One-year variability limits Three-year variability limits 

2014 and thereafter 

(tons) 

2016 and thereafter 

(tons) 

Alabama ....................................................................................................................................................... 2,974 1,717 

Arkansas ...................................................................................................................................................... 2,100 1,212 

Connecticut .................................................................................................................................................. 2,100 1,212 

Delaware ...................................................................................................................................................... 2,100 1,212 

District of Columbia ..................................................................................................................................... 2,100 1,212 

Florida .......................................................................................................................................................... 5,694 3,287 

Georgia ........................................................................................................................................................ 3,214 1,856 

Illinois ........................................................................................................................................................... 2,357 1,361 

Indiana ......................................................................................................................................................... 4,999 2,886 

Kansas ......................................................................................................................................................... 2,143 1,237 

Kentucky ...................................................................................................................................................... 3,091 1,784 

Louisiana ...................................................................................................................................................... 2,122 1,225 

Maryland ...................................................................................................................................................... 2,100 1,212 

Michigan ....................................................................................................................................................... 2,825 1,631 

Mississippi .................................................................................................................................................... 2,100 1,212 

New Jersey .................................................................................................................................................. 2,100 1,212 

New York ..................................................................................................................................................... 2,100 1,212 

North Carolina .............................................................................................................................................. 2,354 1,359 

Ohio ............................................................................................................................................................. 4,066 2,348 

Oklahoma ..................................................................................................................................................... 3,709 2,141 

Pennsylvania ................................................................................................................................................ 4,827 2,787 

South Carolina ............................................................................................................................................. 2,100 1,212 

Tennessee ................................................................................................................................................... 2,100 1,212 

Texas ........................................................................................................................................................... 7,557 4,363 

Virginia ......................................................................................................................................................... 2,100 1,212 

West Virginia ................................................................................................................................................ 2,223 1,284 

§ 97.511 Timing requirements for TR NOX

Ozone Season allowance allocations. 

(a) Existing units. (1) TR NOX Ozone 

Season allowances are allocated, for the 

control periods in 2012 and each year 

thereafter, as set forth in appendix A to 

this subpart. Listing a unit in such 

appendix does not constitute a 

determination that the unit is a TR NOX

Ozone Season unit, and not listing a 

unit in such appendix does not 

constitute a determination that the unit 

is not a TR NOX Ozone Season unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit listed in 

appendix A to this subpart as being 

allocated TR NOX Ozone Season 

allowances does not operate, starting 

after 2011, during the control period in 

three consecutive years, such unit will 

not be allocated the TR NOX Ozone 

Season allowances set forth in appendix 

A to this subpart for the unit for the 

control periods in the seventh year after 

the first such year and in each year after 

that seventh year. All TR NOX Ozone 

Season allowances that would otherwise 

have been allocated to such unit will be 

allocated to the new unit set-aside for 

the respective years involved. If such 

unit resumes operation, the 

Administrator will allocate TR NOX

Ozone Season allowances to the unit in 

accordance with paragraph (b) of this 

section. 

(b) New units. (1) By April 1, 2012 

and April 1 of each year thereafter, the 

Administrator will calculate the TR 

NOX Ozone Season allowance allocation 

for each TR NOX Ozone Season unit, in 

accordance with § 97.512, for the 

control period in the year of the 

applicable calculation deadline under 

this paragraph and will promulgate a 

notice of availability of the results of the 

calculations. 

(2) For each notice of data availability 

required in paragraph (b)(1) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations are in 

accordance with § 97.512 and 

§§ 97.506(b)(2) and 97.530 through 

97.535. 

(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By June 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(c) Units that are not TR NOX Ozone 

Season units. For each control period in 

2012 and thereafter, if the Administrator 

determines that TR NOX Ozone Season 

allowances were allocated under 

paragraph (a) of this section for the 

control period to a recipient that is not 

actually a TR NOX Ozone Season unit 

under § 97.504 as of May 1, 2012 or 

whose deadline for meeting monitor 

certification requirements under 

§ 97.530(b)(1) and (2) is after May 1, 

2012 or if the Administrator determines 

that TR NOX Ozone Season allowances 

were allocated under paragraph (b) of 

this section and § 97.512 for the control 

period to a recipient that is not actually 

a TR NOX Ozone Season unit under 

§ 97.504 as of May 1 of the control 

period, then the Administrator will 

notify the designated representative and 

will act in accordance with the 

following procedures: 

(1) Except as provided in paragraph 

(c)(2) or (3) of this section, the 

Administrator will not record such TR 

NOX Ozone Season allowances under 

§ 97.521. 

(2) If the Administrator already 

recorded such TR NOX Ozone Season 

allowances under § 97.521 and if the 

Administrator makes such 

determination before making deductions 

for the source that includes such 

recipient under § 97.524(b) for such 

control period, then the Administrator 

will deduct from the account in which 

such TR NOX Ozone Season allowances 


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were recorded an amount of TR NOX

Ozone Season allowances allocated for 

the same or a prior control period equal 

to the amount of such already recorded 

TR NOX Ozone Season allowances. The 

authorized account representative shall 

ensure that there are sufficient TR NOX

Ozone Season allowances in such 

account for completion of the 

deduction. 

(3) If the Administrator already 

recorded such TR NOX Ozone Season 

allowances under § 97.521 and if the 

Administrator makes such 

determination after making deductions 

for the source that includes such 

recipient under § 97.524(b) for such 

control period, then the Administrator 

will not make any deduction to take 

account of such already recorded TR 

NOX Ozone Season allowances. 

(4) The Administrator will transfer the 

TR NOX Ozone Season allowances that 

are not recorded, or that are deducted, 

in accordance with paragraphs (c)(1) 

and (2) of this section to the new unit 

set-aside, for the State in which such 

recipient is located, for the control 

period in the year of such transfer if the 

notice required in paragraph (b)(1) of 

this section for the control period in that 

year has not been promulgated or, if 

such notice has been promulgated, in 

the next year. 

§ 97.512 TR NOX Ozone Season allowance 

allocations for new units. 

(a) For each control period in 2012 

and thereafter, the Administrator will 

allocate, in accordance with the 

following procedures, TR NOX Ozone 

Season allowances to TR NOX Ozone 

Season units in a State that are not 

listed in appendix A to this subpart, to 

TR NOX Ozone Season units that are so 

listed and whose allocation of NOX

Ozone Season allowances for such 

control period is covered by 

§ 97.511(c)(1) or (2), and to TR NOX

Ozone Season units that are so listed 

and, pursuant to § 97.511(a)(2), are not 

allocated TR NOX Ozone Season 

allowances for such control period but 

that operate during the immediately 

preceding control period: 

(1) The Administrator will establish a 

separate new unit set-aside for each 

State for each control period in a given 

year. Each new unit set-aside will be 

allocated TR NOX Ozone Season 

allowances in an amount equal to the 

applicable amount of tons of NOX

emissions as set forth in § 97.510(a). 

Each new unit set-aside will be 

allocated additional TR NOX Ozone 

Season allowances in accordance with 

§ 97.511(a)(2) and (c)(4). 

(2) The designated representative of 

such TR NOX Ozone Season unit may 

submit to the Administrator a request, 

in a format prescribed by the 

Administrator, to be allocated TR NOX

Ozone Season allowances for a control 

period, starting with the later of the 

control period in 2012, the first control 

period after the control period in which 

the TR NOX Ozone Season unit 

commences commercial operation (for a 

unit not listed in appendix A to this 

subpart), or the first control period after 

the control period in which the unit 

resumes operation (for a unit listed in 

appendix A of this subpart) and for each 

subsequent control period. 

(i) The request must be submitted on 

or before February 1 immediately 

preceding the first control period for 

which TR NOX Ozone Season 

allowances are sought and after the date 

on which the TR NOX Ozone Season 

unit commences commercial operation 

(for a unit not listed in appendix A of 

this subpart) or on which the unit 

resumes operation (for a unit listed in 

appendix A of this subpart). 

(ii) For each control period for which 

an allocation is sought, the request must 

be for TR NOX Ozone Season 

allowances in an amount equal to the 

unit’s total tons of NOX emissions 

during the immediately preceding 

control period. 

(3) The Administrator will review 

each TR NOX Ozone Season allowance 

allocation request under paragraph 

(a)(2) of this section and will accept the 

request only if it meets the requirements 

of paragraph (a)(2) of this section. The 

Administrator will allocate TR NOX

Ozone Season allowances for each 

control period pursuant to an accepted 

request as follows: 

(i) After February 1 immediately 

preceding such control period, the 

Administrator will determine the sum of 

the TR NOX Ozone Season allowances 

requested in all accepted allowance 

allocation requests for such control 

period. 

(ii) If the amount of TR NOX Ozone 

Season allowances in the new unit setaside for such control period is greater 

than or equal to the sum under 

paragraph (a)(3)(i) of this section, then 

the Administrator will allocate the 

amount of TR NOX Ozone Season 

allowances requested to each TR NOX

Ozone Season unit covered by an 

accepted allowance allocation request. 

(iii) If the amount of TR NOX Ozone 

Season allowances in the new unit setaside for such control period is less than 

the sum under paragraph (a)(3)(i) of this 

section, then the Administrator will 

allocate to each TR NOX Ozone Season 

unit covered by an accepted allowance 

allocation request the amount of the TR 

NOX Ozone Season allowances 

requested, multiplied by the amount of 

TR NOX Ozone Season allowances in 

the new unit set-aside for such control 

period, divided by the sum determined 

under paragraph (a)(3)(i) of this section, 

and rounded to the nearest allowance. 

(iv) The Administrator will notify, 

through the promulgation of the notices 

of data availability described in 

§ 97.511(b), each designated 

representative that submitted an 

allowance allocation request of the 

amount of TR NOX Ozone Season 

allowances (if any) allocated for such 

control period to the TR NOX Ozone 

Season unit covered by the request. 

(b) If, after completion of the 

procedures under paragraph (a)(4) of 

this section for a control period, any 

unallocated TR NOX Ozone Season 

allowances remain in the new unit setaside under paragraph (a) of this section 

for a State for such control period, the 

Administrator will allocate to each TR 

NOX Ozone Season unit that is in the 

State, is listed in appendix A to this 

subpart, and continues to be allocated 

TR NOX Ozone Season allowances for 

such control period in accordance with 

§ 97.511(a)(2), an amount of TR NOX

Ozone Season allowances equal to the 

following: The total amount of such 

remaining unallocated TR NOX Ozone 

Season allowances in such new unit setaside, multiplied by the unit’s allocation 

under § 97.511(a) for such control 

period, divided by the remainder of the 

amount of tons in the applicable State 

NOX Ozone Season trading budget 

minus the amount of tons in such new 

unit set-aside, and rounded to the 

nearest allowance. 

§ 97.513 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.515, 

each TR NOX Ozone Season source, 

including all TR NOX Ozone Season 

units at the source, shall have one and 

only one designated representative, with 

regard to all matters under the TR NOX

Ozone Season Trading Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR NOX Ozone 

Season units at the source and shall act 

in accordance with the certification 

statement in § 97.516(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.516: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR NOX Ozone Season unit at 


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the source in all matters pertaining to 

the TR NOX Ozone Season Trading 

Program, notwithstanding any 

agreement between the designated 

representative and such owners and 

operators; and 

(ii) The owners and operators of the 

source and each TR NOX Ozone Season 

unit at the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.515, 

each TR NOX Ozone Season source may 

have one and only one alternate 

designated representative, who may act 

on behalf of the designated 

representative. The agreement by which 

the alternate designated representative 

is selected shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR NOX

Ozone Season units at the source and 

shall act in accordance with the 

certification statement in 

§ 97.516(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.516, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each TR NOX Ozone Season 

unit at the source shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(c) Except in this section, § 97.502, 

and §§ 97.514 through 97.518, whenever 

the term ‘‘designated representative’’ is 

used in this subpart, the term shall be 

construed to include the designated 

representative or any alternate 

designated representative. 

§ 97.514 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.518 

concerning delegation of authority to 

make submissions, each submission 

under the TR NOX Ozone Season 

Trading Program shall be made, signed, 

and certified by the designated 

representative or alternate designated 

representative for each TR NOX Ozone 

Season source and TR NOX Ozone 

Season unit for which the submission is 

made. Each such submission shall 

include the following certification 

statement by the designated 

representative or alternate designated 

representative: ‘‘I am authorized to make 

this submission on behalf of the owners 

and operators of the source or units for 

which the submission is made. I certify 

under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR NOX

Ozone Season source or a TR NOX

Ozone Season unit only if the 

submission has been made, signed, and 

certified in accordance with paragraph 

(a) of this section and § 97.518. 

§ 97.515 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators. 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.516. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the TR NOX Ozone Season 

source and the TR NOX Ozone Season 

units at the source. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.516. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the TR NOX

Ozone Season source and the TR NOX

Ozone Season units at the source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a TR NOX Ozone Season source or a TR 

NOX Ozone Season unit is not included 

in the list of owners and operators in the 

certificate of representation under 

§ 97.516, such owner or operator shall 

be deemed to be subject to and bound 

by the certificate of representation, the 

representations, actions, inactions, and 

submissions of the designated 

representative and any alternate 

designated representative of the source 

or unit, and the decisions and orders of 

the Administrator, as if the owner or 

operator were included in such list. 

(2) Within 30 days after any change in 

the owners and operators of a TR NOX

Ozone Season source or a TR NOX

Ozone Season unit, including the 

addition of a new owner or operator, the 

designated representative or any 

alternate designated representative shall 

submit a revision to the certificate of 

representation under § 97.516 amending 

the list of owners and operators to 

include the change. 

§ 97.516 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR NOX

Ozone Season source, and each TR NOX

Ozone Season unit at the source, for 

which the certificate of representation is 

submitted, including source name, 

source category and NAICS code (or, in 

the absence of a NAICS code, an 

equivalent code), State, plant code, 

county, latitude and longitude, unit 

identification number and type, 

identification number and nameplate 

capacity (in MWe rounded to the 

nearest tenth) of each generator served 

by each such unit, and actual or 

projected date of commencement of 

commercial operation. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR NOX Ozone Season source and 

of each TR NOX Ozone Season unit at 

the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 


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(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

NOX Ozone Season unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

NOX Ozone Season Trading Program on 

behalf of the owners and operators of 

the source and of each TR NOX Ozone 

Season unit at the source and that each 

such owner and operator shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

order issued to me by the Administrator 

regarding the source or unit.’’ 

(iii) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a TR NOX Ozone 

Season unit, or where a utility or 

industrial customer purchases power 

from a TR NOX Ozone Season unit 

under a life-of-the-unit, firm power 

contractual arrangement, I certify that: I 

have given a written notice of my 

selection as the ‘designated 

representative’ or ‘alternate designated 

representative’, as applicable, and of the 

agreement by which I was selected to 

each owner and operator of the source 

and of each TR NOX Ozone Season unit 

at the source; and TR NOX Ozone 

Season allowances and proceeds of 

transactions involving TR NOX Ozone 

Season allowances will be deemed to be 

held or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of TR NOX Ozone Season 

allowances by contract, TR NOX Ozone 

Season allowances and proceeds of 

transactions involving TR NOX Ozone 

Season allowances will be deemed to be 

held or distributed in accordance with 

the contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 97.517 Objections concerning 

designated representative and alternate 

designated representative. 

(a) Once a complete certificate of 

representation under § 97.516 has been 

submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 97.516 is 

received by the Administrator. 

(b) Except as provided in § 97.515(a) 

or (b), no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the TR NOX Ozone Season 

Trading Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of TR 

NOX Ozone Season allowance transfers. 

§ 97.518 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (a) or (b) of this section, the 

designated representative or alternate 

designated representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to as an 

‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.518(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.518(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.518 is terminated.’’. 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.519 [Reserved] 

§ 97.520 Establishment of Allowance 

Management System accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.516, the 

Administrator will establish a 

compliance account for the TR NOX

Ozone Season source for which the 

certificate of representation was 

submitted, unless the source already has 

a compliance account. The designated 

representative and any alternate 

designated representative of the source 


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shall be the authorized account 

representative and the alternate 

authorized account representative 

respectively of the compliance account. 

(b) General accounts—(1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring TR 

NOX Ozone Season allowances, by 

submitting to the Administrator a 

complete application for a general 

account. Such application shall 

designate one and only one authorized 

account representative and may 

designate one and only one alternate 

authorized account representative who 

may act on behalf of the authorized 

account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR NOX Ozone Season 

allowances held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the TR NOX Ozone Season 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR NOX Ozone Season 

allowances held in the general account. 

I certify that I have all the necessary 

authority to carry out my duties and 

responsibilities under the TR NOX

Ozone Season Trading Program on 

behalf of such persons and that each 

such person shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order or 

decision issued to me by the 

Administrator regarding the general 

account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. 

(i) Upon receipt by the Administrator of 

a complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to TR 

NOX Ozone Season allowances held in 

the general account in all matters 

pertaining to the TR NOX Ozone Season 

Trading Program, notwithstanding any 

agreement between the authorized 

account representative and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to TR 

NOX Ozone Season allowances held in 

the general account shall be bound by 

any order or decision issued to the 

authorized account representative or 

alternate authorized account 

representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph 

(b)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account shall be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to TR 

NOX Ozone Season allowances held in 

the general account. Each such 

submission shall include the following 

certification statement by the authorized 

account representative or any alternate 

authorized account representative: ‘‘I am 

authorized to make this submission on 

behalf of the persons having an 

ownership interest with respect to the 

TR NOX Ozone Season allowances held 

in the general account. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(b)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR NOX Ozone 

Season allowances in the general 

account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 


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alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR NOX Ozone Season allowances in 

the general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR NOX Ozone Season allowances in 

the general account is not included in 

the list of such persons in the 

application for a general account, such 

person shall be deemed to be subject to 

and bound by the application for a 

general account, the representation, 

actions, inactions, and submissions of 

the authorized account representative 

and any alternate authorized account 

representative of the account, and the 

decisions and orders of the 

Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to NOX Ozone 

Season allowances in the general 

account, including the addition of a new 

person, the authorized account 

representative or any alternate 

authorized account representative shall 

submit a revision to the application for 

a general account amending the list of 

persons having an ownership interest 

with respect to the TR NOX Ozone 

Season allowances in the general 

account to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. 

(i) Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account shall affect any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative or the 

finality of any decision or order by the 

Administrator under the TR NOX Ozone 

Season Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

NOX Ozone Season allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (b)(5)(i) or (ii) of this section, 

the authorized account representative or 

alternate authorized account 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(B) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such natural person (referred to 

as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (b)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 

97.520(b)(5)(iv) shall be deemed to be an 

electronic submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 40 

CFR 97.520(b)(5)(iv), I agree to maintain 

an e-mail account and to notify the 

Administrator immediately of any 

change in my e-mail address unless all 

delegation of authority by me under 40 

CFR 97.520(b)(5) is terminated.’’. 

(iv) A notice of delegation submitted 

under paragraph (b)(5)(iii) of this 

section shall be effective, with regard to 

the authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

(v) Any electronic submission covered 

by the certification in paragraph 

(b)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (b)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

(6)(i) The authorized account 

representative or alternate authorized 

account representative of a general 

account may submit to the 

Administrator a request to close the 

account. Such request shall include a 

correctly submitted TR NOX Ozone 

Season allowance transfer under 

§ 97.522 for any TR NOX Ozone Season 

allowances in the account to one or 

more other Allowance Management 

System accounts. 

(ii) If a general account has no TR 

NOX Ozone Season allowance transfers 

to or from the account for a 12-month 

period or longer and does not contain 

any TR NOX Ozone Season allowances, 

the Administrator may notify the 

authorized account representative for 

the account that the account will be 

closed after 20 business days after the 

notice is sent. The account will be 

closed after the 20-day period unless, 

before the end of the 20-day period, the 

Administrator receives a correctly 

submitted TR NOX Ozone Season 

allowance transfer under § 97.522 to the 

account or a statement submitted by the 

authorized account representative or 

alternate authorized account 

representative demonstrating to the 

satisfaction of the Administrator good 


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cause as to why the account should not 

be closed. 

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section. 

(d) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of an Allowance 

Management System account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of TR NOX Ozone Season 

allowances in the account, only if the 

submission has been made, signed, and 

certified in accordance with §§ 97.514(a) 

and 97.518 or paragraphs (b)(2)(ii) and 

(b)(5) of this section. 

§ 97.521 Recordation of TR NOX Ozone 

Season allowance allocations. 

(a) By September 1, 2011, the 

Administrator will record in each TR 

NOX Ozone Season source’s compliance 

account the TR NOX Ozone Season 

allowances allocated for the TR NOX

Ozone Season units at the source in 

accordance with §§ 97.511(a) for the 

control periods in 2012, 2013, and 2014. 

(b) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

record in each TR NOX Ozone Season 

source’s compliance account the TR 

NOX Ozone Season allowances allocated 

for the TR NOX Ozone Season units at 

the source in accordance with 

§ 97.511(a) for the control period in the 

third year after the year of the 

applicable recordation deadline under 

this paragraph. 

(c) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

record in each TR NOX Ozone Season 

source’s compliance account the TR 

NOX Ozone Season allowances allocated 

for the TR NOX Ozone Season units at 

the source in accordance with § 97.512 

for the control period in the year of the 

applicable recordation deadline under 

this paragraph. 

(d) When recording the allocation of 

TR NOX Ozone Season allowances for a 

TR NOX Ozone Season unit in a 

compliance account, the Administrator 

will assign each TR NOX Ozone Season 

allowance a unique identification 

number that will include digits 

identifying the year of the control 

period for which the TR NOX Ozone 

Season allowance is allocated. 

§ 97.522 Submission of TR NOX Ozone 

Season allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR NOX Ozone Season allowance 

transfer shall submit the transfer to the 

Administrator. 

(b) A TR NOX Ozone Season 

allowance transfer shall be correctly 

submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR NOX

Ozone Season allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR NOX Ozone 

Season allowance identified by serial 

number in the transfer. 

§ 97.523 Recordation of TR NOX Ozone 

Season allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR NOX Ozone 

Season allowance transfer, the 

Administrator will record a TR NOX

Ozone Season allowance transfer by 

moving each TR NOX Ozone Season 

allowance from the transferor account to 

the transferee account as specified by 

the request, provided that the transfer is 

correctly submitted under § 97.522. 

(b)(1) A TR NOX Ozone Season 

allowance transfer that is submitted for 

recordation after the allowance transfer 

deadline for a control period and that 

includes any TR NOX Ozone Season 

allowances allocated for any control 

period before such allowance transfer 

deadline will not be recorded until after 

the Administrator completes the 

deductions under § 97.524 for the 

control period immediately before such 

allowance transfer deadline. 

(2) A TR NOX Ozone Season 

allowance transfer that is submitted for 

recordation after the deadline for 

holding TR NOX Ozone Season 

allowances described in § 97.525(b)(5) 

and that includes any TR NOX Ozone 

Season allowances allocated for a 

control period before the year of such 

deadline will not be recorded until after 

the Administrator completes the 

deductions under § 97.525 for the 

control period immediately before the 

year of such deadline. 

(c) Where a TR NOX Ozone Season 

allowance transfer is not correctly 

submitted under § 97.522, the 

Administrator will not record such 

transfer. 

(d) Within 5 business days of 

recordation of a TR NOX Ozone Season 

allowance transfer under paragraphs (a) 

and (b) of the section, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR NOX Ozone Season allowance 

transfer that is not correctly submitted 

under § 97.522, the Administrator will 

notify the authorized account 

representatives of both accounts subject 

to the transfer of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.524 Compliance with TR NOX Ozone 

Season emissions limitation. 

(a) Availability for deduction for 

compliance. TR NOX Ozone Season 

allowances are available to be deducted 

for compliance with a source’s TR NOX

Ozone Season emissions limitation for a 

control period in a given year only if the 

TR NOX Ozone Season allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in the source’s 

compliance account as of the allowance 

transfer deadline for such control 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 97.523, of TR NOX Ozone Season 

allowance transfers submitted by the 

allowance transfer deadline for a control 

period, the Administrator will deduct 

from the compliance account TR NOX

Ozone Season allowances available 

under paragraph (a) of this section in 

order to determine whether the source 

meets the TR NOX Ozone Season 

emissions limitation for such control 

period, as follows: 

(1) Until the amount of TR NOX

Ozone Season allowances deducted 

equals the number of tons of total NOX

emissions from all TR NOX Ozone 

Season units at the source for such 

control period; or 

(2) If there are insufficient TR NOX

Ozone Season allowances to complete 

the deductions in paragraph (b)(1) of 

this section, until no more TR NOX

Ozone Season allowances available 

under paragraph (a) of this section 

remain in the compliance account. 

(c)(1) Identification of TR NOX Ozone 

Season allowances by serial number. 

The authorized account representative 

for a source’s compliance account may 

request that specific TR NOX Ozone 

Season allowances, identified by serial 

number, in the compliance account be 

deducted for emissions or excess 

emissions for a control period in 


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accordance with paragraph (b) or (d) of 

this section. In order to be complete, 

such request shall be submitted to the 

Administrator by the allowance transfer 

deadline for such control period and 

include, in a format prescribed by the 

Administrator, the identification of the 

TR NOX Ozone Season source and the 

appropriate serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR NOX

Ozone Season allowances under 

paragraph (b) or (d) of this section from 

the source’s compliance account in 

accordance with a complete request 

under paragraph (c)(1) of this section or, 

in the absence of such request or in the 

case of identification of an insufficient 

amount of TR NOX Ozone Season 

allowances in such request, on a first-in, 

first-out (FIFO) accounting basis in the 

following order: 

(i) Any TR NOX Ozone Season 

allowances that were allocated to the 

units at the source and not transferred 

out of the compliance account, in the 

order of recordation; and then 

(ii) Any TR NOX Ozone Season 

allowances that were allocated to any 

unit and transferred to and recorded in 

the compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a year in 

which the TR NOX Ozone Season source 

has excess emissions, the Administrator 

will deduct from the source’s 

compliance account an amount of TR 

NOX Ozone Season allowances, 

allocated for the control period in the 

immediately following year, equal to 

two times the number of tons of the 

source’s excess emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.525 Compliance with TR NOX Ozone 

Season assurance provisions. 

(a) Availability for deduction. TR NOX

Ozone Season allowances are available 

to be deducted for compliance with the 

TR NOX Ozone Season assurance 

provisions for a control period in a 

given year by an owner of one or more 

TR NOX Ozone Season units in a State 

only if the TR NOX Ozone Season 

allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in a compliance account, 

designated by the owner in accordance 

with paragraph (b)(4)(ii) of this section, 

of one of the owner’s TR NOX Ozone 

Season sources in the State as of the 

deadline established in paragraph (b)(5) 

of this section. 

(b) Deductions for compliance. The 

Administrator will deduct TR NOX

Ozone Season allowances available 

under paragraph (a) of this section for 

compliance with the TR NOX Ozone 

Season assurance provisions for a State 

for a control period in a given year in 

accordance with the following 

procedures: 

(1) By March 1, 2015 and March 1 of 

each year thereafter, the Administrator 

will: 

(i) Calculate, separately for each State, 

the total amount of NOX emissions from 

all TR NOX Ozone Season units in the 

State during the control period in the 

year before the year of this calculation 

deadline and the amount, if any, by 

which such total amount of NOX

emissions exceeds the State assurance 

level as described in § 97.506(c)(2)(iii); 

and 

(ii) Promulgate a notice of availability 

of the results of the calculations 

required in paragraph (b)(1)(i) of this 

section, including separate calculations 

of the NOX emissions for each TR NOX

Ozone Season unit and of the amounts 

described in §§ 97.506(c)(2)(iii)(A) and 

(B) for each State. 

(2) The Administrator will provide an 

opportunity for submission of objections 

to the calculations referenced by each 

notice described in paragraph (b)(1) of 

this section. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each TR 

NOX Ozone Season unit and each State 

for the control period in the year 

involved are in accordance with 

§ 97.506(c)(2)(iii) and §§ 97.506(b) and 

97.530 through 97.535. 

(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By May 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(3) For each notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and for any State identified in 

such notice as having TR NOX Ozone 

Season sources with total NOX

emissions exceeding the State assurance 

level for a control period, as described 

in § 97.506(c)(2)(iii): 

(i) By May 15 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

NOX Ozone Season source in each such 

State shall submit a statement, in a 

format prescribed by the Administrator: 

(A) Listing all the owners of each TR 

NOX Ozone Season unit at the source, 

explaining how the selection of each 

owner for inclusion on the list is 

consistent with the definition of 

‘‘owner’’ in § 97.502, and listing, 

separately for each unit, the percentage 

of the legal, equitable, leasehold, or 

contractual reservation or entitlement 

for each such owner as of midnight of 

December 31 of the control period in the 

year involved; and 

(B) For each TR NOX Ozone Season 

unit at the source that operates during, 

but is allocated no TR NOX Ozone 

Season allowances for, the control 

period in the year involved, identifying 

whether the unit is a coal-fired boiler, 

simple combustion turbine, or 

combined cycle turbine cycle and 

providing the unit’s allowable NOX

emission rate for such control period. 

(ii) By June 15 immediately after the 

promulgation of such notice, the 

Administrator will calculate, for each 

such State and each owner of one or 

more TR NOX Ozone Season units in the 

State and for the control period in the 

year involved, each owner’s share of the 

total NOX emissions from all TR NOX

Ozone Season units in the State, each 

owner’s assurance level, and the amount 

(if any) of TR NOX Ozone Season 

allowances that each owner must hold 

in accordance with the calculation 

formula in § 97.506(c)(2)(i) and will 

promulgate a notice of availability of the 

results of these calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 

required in paragraph (b)(3)(ii) of this 

section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each owner 

for the control period in the year 

involved are consistent with the NOX

emissions for the relevant TR NOX

Ozone Season units as set forth in the 

notice required in paragraph (b)(2)(ii) of 

this section, the definitions of ‘‘owner’’, 

‘‘owner’s assurance level’’, and ‘‘owner’s 

share’’ in § 97.502, and the calculation 

formula in § 97.506(c)(2)(i) and shall not 

raise any issues about any data used in 

the notice of data availability required 

in paragraph (b)(2)(ii) of this section. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are consistent with the 

data and provisions referenced in 

paragraph (b)(3)(iii)(A) of this section. 


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By August 15 immediately after the 

promulgation of such notice, the 

Administrator will promulgate a notice 

of availability of any adjustments that 

the Administrator determines to be 

necessary and the reasons for accepting 

or rejecting any objections submitted in 

accordance with paragraph (b)(3)(iii)(A) 

of this section. 

(4) By September 1 immediately after 

the promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section: 

(i) Each owner identified, in such 

notice, as owning one or more TR NOX

Ozone Season units in a State and as 

being required to hold TR NOX Ozone 

Season allowances shall designate the 

compliance account of one of the 

sources at which such unit or units are 

located to hold such required TR NOX

Ozone Season allowances; 

(ii) The authorized account 

representative for the compliance 

account designated under paragraph 

(b)(4)(i) of this section shall submit to 

the Administrator a statement, in a 

format prescribed by the Administrator, 

making this designation. 

(5)(i) As of midnight of September 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(3)(iii)(B) of this section, 

each owner described in paragraph 

(b)(4)(i) of this section shall hold in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section the total amount 

of TR NOX Ozone Season allowances, 

available for deduction under paragraph 

(a) of this section, equal to the amount 

the owner is required to hold as 

calculated by the Administrator and 

referenced in such notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(5)(i) of this section, if September 15 

is not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(6) After September 15 (or the date 

described in paragraph (b)(5)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.523, of TR NOX Ozone Season 

allowance transfers submitted by 

midnight of such date, the 

Administrator will deduct from each 

compliance account designated in 

accordance with paragraph (b)(4)(ii) of 

this section, TR NOX Ozone Season 

allowances available under paragraph 

(a) of this section, as follows: 

(i) Until the amount of TR NOX Ozone 

Season allowances deducted equals the 

amount that the owner designating the 

compliance account is required to hold 

as calculated by the Administrator and 

referenced in the notice required in 

paragraph (b)(3)(iii)(B) of this section; or 

(ii) If there are insufficient TR NOX

Ozone Season allowances to complete 

the deductions in paragraph (b)(6)(i) of 

this section, until no more TR NOX

Ozone Season allowances available 

under paragraph (a) of this section 

remain in the compliance account. 

(7) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notices of data availability required 

in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) 

of this section respectively for a control 

period, of any data used in making the 

calculations referenced in such notice, 

the amount of TR NOX Ozone Season 

allowances that each owner is required 

to hold in accordance with 

§ 97.506(c)(2)(i) for the control period in 

the year involved shall continue to be 

such amount as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(3)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR NOX Ozone Season allowances 

that owners are required to hold in 

accordance with the calculation formula 

in § 97.506(c)(2)(i) for the control period 

in the year involved with regard to the 

State involved, provided that— 

(A) With regard to such litigation 

involving such notice required in 

paragraph (b)(2)(ii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(ii) of this section; and 

(B) With regard to such litigation 

involving such notice required in 

paragraph (b)(3)(iii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(3)(iii) of this section. 

(ii) If any such data are revised by the 

owners and operators of a source whose 

designated representative submitted 

such data under paragraph (b)(3)(i) of 

this section, as a result of a decision in 

or settlement of litigation concerning 

such submission, then the 

Administrator will use the data as so 

revised to recalculate the amounts of TR 

NOX Ozone Season allowances that 

owners are required to hold in 

accordance with the calculation formula 

in § 97.506(c)(2)(i) for the control period 

in the year involved with regard to the 

State involved, provided that such 

litigation was initiated no later than 30 

days after promulgation of such notice 

required in paragraph (b)(3)(iii)(B) of 

this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(7)(i) and (b)(7)(ii) of this 

section, the amount of TR NOX Ozone 

Season allowances that an owner is 

required to hold for the control period 

in the year involved with regard to the 

State involved- 

(A) Where the amount of TR NOX

Ozone Season allowances that an owner 

is required to hold increases as a result 

of the use of all such revised data, the 

Administrator will establish a new, 

reasonable deadline on which the owner 

shall hold the additional amount of TR 

NOX Ozone Season allowances in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section. The owner’s 

failure to hold such additional amount, 

as required, before the new deadline 

shall not be a violation of the Clean Air 

Act. The owner’s failure to hold such 

additional amount, as required, as of the 

new deadline shall be a violation of the 

Clean Air Act. Each TR NOX Ozone 

Season allowance that the owner fails to 

hold as required as of the new deadline, 

and each day in the control period in 

the year involved, shall be a separate 

violation of the Clean Air Act. After 

such deadline, the Administrator will 

make the appropriate deductions from 

the compliance account. 

(B) For an owner for which the 

amount of TR NOX Ozone Season 

allowances required to be held 

decreases as a result of the use of all 

such revised data, the Administrator 

will record, in the compliance account 

that the owner designated in accordance 

with paragraph (b)(4)(ii) of this section, 

an amount of TR NOX Ozone Season 

allowances equal to the amount of the 

decrease to the extent such amount was 

previously deducted from the 

compliance account under paragraph 

(b)(6) of this section (and has not 

already been restored to the compliance 


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account) for the control period in the 

year involved. 

(C) Each TR NOX Ozone Season 

allowance held and deducted under 

paragraph (b)(7)(iii)(A) of this section, or 

recorded under paragraph (b)(7)(iii)(B) 

of this section, as a result of 

recalculation of requirements for 

compliance with the TR NOX Ozone 

Season assurance provisions for a 

control period in a given year must be 

a TR NOX Ozone Season allowance 

allocated for a control period in the 

same or a prior year. 

(c)(1) Identification of TR NOX Ozone 

Season allowances by serial number. 

The authorized account representative 

for each source’s compliance account 

designated in accordance with 

paragraph (b)(4)(ii) of this section may 

request that specific TR NOX Ozone 

Season allowances, identified by serial 

number, in the compliance account be 

deducted in accordance with paragraph 

(b)(6) or (7) of this section. In order to 

be complete, such request shall be 

submitted to the Administrator by the 

allowance-holding deadline described 

in paragraph (b)(5) of this section and 

include, in a format prescribed by the 

Administrator, the identification of the 

compliance account and the appropriate 

serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR NOX

Ozone Season allowances under 

paragraphs (b)(6) and (7) of this section 

from each source’s compliance account 

designated under paragraph (b)(4)(ii) of 

this section in accordance with a 

complete request under paragraph (c)(1) 

of this section or, in the absence of such 

request or in the case of identification 

of an insufficient amount of TR NOX

Ozone Season allowances in such 

request, on a first-in, first-out (FIFO) 

accounting basis in the following order: 

(i) Any TR NOX Ozone Season 

allowances that were allocated to the 

units at the source and not transferred 

out of the compliance account, in the 

order of recordation; and then 

(ii) Any TR NOX Ozone Season 

allowances that were allocated to any 

unit and transferred to and recorded in 

the compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) of this section. 

§ 97.526 Banking. 

(a) A TR NOX Ozone Season 

allowance may be banked for future use 

or transfer in a compliance account or 

a general account in accordance with 

paragraph (b) of this section. 

(b) Any TR NOX Ozone Season 

allowance that is held in a compliance 

account or a general account will 

remain in such account unless and until 

the TR NOX Ozone Season allowance is 

deducted or transferred under 

§ 97.511(c), § 97.523, § 97.524, § 97.525, 

97.527, 97.528, 97.542, or 97.543. 

§ 97.527 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.528 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR NOX

Ozone Season Trading Program and 

make appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

NOX Ozone Season allowances from or 

transfer TR NOX Ozone Season 

allowances to a source’s compliance 

account based on the information in a 

submission, as adjusted under 

paragraph (a)(1) of this section, and 

record such deductions and transfers. 

§ 97.529 [Reserved] 

§ 97.530 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR NOX Ozone 

Season unit, shall comply with the 

monitoring, recordkeeping, and 

reporting requirements as provided in 

this subpart and subpart H of part 75 of 

this chapter. For purposes of applying 

such requirements, the definitions in 

§ 97.502 and in § 72.2 of this chapter 

shall apply, the terms ‘‘affected unit,’’ 

‘‘designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) in part 75 of this 

chapter shall be deemed to refer to the 

terms ‘‘TR NOX Ozone Season unit,’’ 

‘‘designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) respectively as 

defined in § 97.502, and the term ‘‘newly 

affected unit’’ shall be deemed to mean 

‘‘newly affected TR NOX Ozone Season 

unit’’. The owner or operator of a unit 

that is not a TR NOX Ozone Season unit 

but that is monitored under 

§ 75.72(b)(2)(ii) of this chapter shall 

comply with the same monitoring, 

recordkeeping, and reporting 

requirements as a TR NOX Ozone 

Season unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR NOX

Ozone Season unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring NOX mass emissions and 

individual unit heat input (including all 

systems required to monitor NOX

emission rate, NOX concentration, stack 

gas moisture content, stack gas flow 

rate, CO2 or O2 concentration, and fuel 

flow rate, as applicable, in accordance 

with §§ 75.71 and 75.72 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.531 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates. The owner or 

operator shall record, report, and 

quality-assure the data from the 

monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

NOX Ozone Season unit that 

commences commercial operation 

before July 1, 2011, by May 1, 2012. 

(2) For the owner or operator of a TR 

NOX Ozone Season unit that 

commences commercial operation on or 

after July 1, 2011 and that reports on an 

annual basis under § 97.534(d), by the 

later of the following dates: 

(i) 180 calendar days, whichever 

occurs first, after the date on which the 

unit commences commercial operation; 

or 

(ii) May 1, 2012. 

(3) For the owner or operator of a TR 

NOX Ozone Season unit that 

commences commercial operation on or 

after July 1, 2011 and that reports on a 

control period basis under 

§ 97.534(d)(2)(ii), by the later of the 

following dates: 

(i) 180 calendar days, whichever 

occurs first, after the date on which the 

unit commences commercial operation; 

or 

(ii) If the compliance date under 

paragraph (b)(3)(i) of this section is not 

during a control period, May 1 

immediately after the compliance date 

under paragraph (b)(3)(i) of this section. 

(4) For the owner or operator of a TR 

NOX Ozone Season unit for which 


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construction of a new stack or flue or 

installation of add-on NOX emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1) or (2) of this section and that 

reports on an annual basis under 

§ 97.534(d), by 90 unit operating days or 

180 calendar days, whichever occurs 

first, after the date on which emissions 

first exit to the atmosphere through the 

new stack or flue or add-on NOX

emissions controls. 

(5) For the owner or operator of a TR 

NOX Ozone Season unit for which 

construction of a new stack or flue or 

installation of add-on NOX emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1) or (3) of this section and that 

reports on a control period basis under 

§ 97.534(d)(2)(ii), by the later of the 

following dates: 

(i) 90 unit operating days or 180 

calendar days, whichever occurs first, 

after the date on which emissions first 

exit to the atmosphere through the new 

stack or flue or add-on NOX emissions 

controls; or 

(ii) If the compliance date under 

paragraph (b)(5)(i) of this section is not 

during a control period, May 1 

immediately after the compliance date 

under paragraph (b)(5)(i) of this section. 

(6) Notwithstanding the dates in 

paragraphs (b)(1), (2), and (3) of this 

section, for the owner or operator of a 

unit for which a TR opt-in application 

is submitted and not withdrawn and is 

not yet approved or disapproved, by the 

date specified in § 97.541(c). 

(7) Notwithstanding the dates in 

paragraphs (b)(1), (2), and (3) of this 

section, for the owner or operator of a 

TR NOX Ozone Season opt-in unit, by 

the date on which the TR NOX Annual 

opt-in unit enters the TR NOX Ozone 

Season Trading Program as provided in 

§ 97.541(h). 

(c) Reporting data. The owner or 

operator of a TR NOX Ozone Season unit 

that does not meet the applicable 

compliance date set forth in paragraph 

(b) of this section for any monitoring 

system under paragraph (a)(1) of this 

section shall, for each such monitoring 

system, determine, record, and report 

maximum potential (or, as appropriate, 

minimum potential) values for NOX

concentration, NOX emission rate, stack 

gas flow rate, stack gas moisture 

content, fuel flow rate, and any other 

parameters required to determine NOX

mass emissions and heat input in 

accordance with § 75.31(b)(2) or (c)(3) of 

this chapter, section 2.4 of appendix D 

to part 75 of this chapter, or section 2.5 

of appendix E to part 75 of this chapter, 

as applicable. 

(d) Prohibitions. (1) No owner or 

operator of a TR NOX Ozone Season unit 

shall use any alternative monitoring 

system, alternative reference method, or 

any other alternative to any requirement 

of this subpart without having obtained 

prior written approval in accordance 

with § 97.535. 

(2) No owner or operator of a TR NOX

Ozone Season unit shall operate the unit 

so as to discharge, or allow to be 

discharged, NOX emissions to the 

atmosphere without accounting for all 

such emissions in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter. 

(3) No owner or operator of a TR NOX

Ozone Season unit shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording NOX mass emissions 

discharged into the atmosphere or heat 

input, except for periods of 

recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the applicable provisions of this 

subpart and part 75 of this chapter. 

(4) No owner or operator of a TR NOX

Ozone Season unit shall retire or 

permanently discontinue use of the 

continuous emission monitoring system, 

any component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.505 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.531(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR NOX Ozone Season 

unit is subject to the applicable 

provisions of § 75.4(d) of this chapter 

concerning units in long-term cold 

storage. 

§ 97.531 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR NOX

Ozone Season unit shall be exempt from 

the initial certification requirements of 

this section for a monitoring system 

under § 97.530(a)(1) if the following 

conditions are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B, D, and E to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.530(a)(1) exempt 

from initial certification requirements 

under paragraph (a) of this section. 

(c) If the Administrator has previously 

approved a petition under § 75.17(a) or 

(b) of this chapter for apportioning the 

NOX emission rate measured in a 

common stack or a petition under 

§ 75.66 of this chapter for an alternative 

to a requirement in § 75.12 or § 75.17 of 

this chapter, the designated 

representative shall resubmit the 

petition to the Administrator under 

§ 97.535 to determine whether the 

approval applies under the TR NOX

Ozone Season Trading Program. 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR NOX Ozone Season unit shall 

comply with the following initial 

certification and recertification 

procedures for a continuous monitoring 

system (i.e., a continuous emission 

monitoring system and an excepted 

monitoring system under appendices D 

and E to part 75 of this chapter) under 

§ 97.530(a)(1). The owner or operator of 

a unit that qualifies to use the low mass 

emissions excepted monitoring 

methodology under § 75.19 of this 

chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.530(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.530(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 


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45412 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.530(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record NOX mass emissions or heat 

input rate or to meet the qualityassurance and quality-control 

requirements of § 75.21 of this chapter 

or appendix B to part 75 of this chapter, 

the owner or operator shall recertify the 

monitoring system in accordance with 

§ 75.20(b) of this chapter. Furthermore, 

whenever the owner or operator makes 

a replacement, modification, or change 

to the flue gas handling system or the 

unit’s operation that may significantly 

change the stack flow or concentration 

profile, the owner or operator shall 

recertify each continuous emission 

monitoring system whose accuracy is 

potentially affected by the change, in 

accordance with § 75.20(b) of this 

chapter. Examples of changes to a 

continuous emission monitoring system 

that require recertification include: 

Replacement of the analyzer, complete 

replacement of an existing continuous 

emission monitoring system, or change 

in location or orientation of the 

sampling probe or site. Any fuel 

flowmeter systems, and any excepted 

NOX monitoring system under appendix 

E to part 75 of this chapter, under 

§ 97.530(a)(1) are subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.530(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 

procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word ‘‘certified’’ 

is replaced by with the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.533. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR NOX Ozone Season Trading 

Program for a period not to exceed 120 

days after receipt by the Administrator 

of the complete certification application 

for the monitoring system under 

paragraph (d)(3)(ii) of this section. Data 

measured and recorded by the 

provisionally certified monitoring 

system, in accordance with the 

requirements of part 75 of this chapter, 

will be considered valid quality-assured 

data (retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR NOX Ozone Season 

Trading Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. The 120-day 

review period specified in paragraph 

(d)(3) of this section shall not begin 

before receipt of a complete certification 

application. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.532(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved NOX emission 

rate (i.e., NOX-diluent) system, the 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(2) For a disapproved NOX pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

NOX and the maximum potential flow 

rate, as defined in sections 2.1.2.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(3) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(4) For a disapproved fuel flowmeter 

system, the maximum potential fuel 


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flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(5) For a disapproved excepted NOX

monitoring system under appendix E to 

part 75 of this chapter, the fuel-specific 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.532 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or subpart H of, or appendix 

D or appendix E to, part 75 of this 

chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.531 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

Administrator or any permitting 

authority. By issuing the notice of 

disapproval, the Administrator revokes 

prospectively the certification status of 

the monitoring system. The data 

measured and recorded by the 

monitoring system shall not be 

considered valid quality-assured data 

from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 97.531 for each 

disapproved monitoring system. 

§ 97.533 Notifications concerning 

monitoring. 

The designated representative of a TR 

NOX Ozone Season unit shall submit 

written notice to the Administrator in 

accordance with § 75.61 of this chapter. 

§ 97.534 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in this section, the 

applicable recordkeeping and reporting 

requirements under § 75.73 of this 

chapter, and the requirements of 

§ 97.514(a). 

(b) Monitoring plans. The owner or 

operator of a TR NOX Ozone Season unit 

shall comply with requirements of 

§ 75.73(c) and (e) of this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.531, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) If the TR NOX Ozone Season unit 

is subject to the Acid Rain Program or 

a TR NOX Annual emissions limitation 

or if the owner or operator of such unit 

chooses to report on an annual basis 

under this subpart, the designated 

representative shall meet the 

requirements of subpart H of part 75 of 

this chapter (concerning monitoring of 

NOX mass emissions) for such unit for 

the entire year and shall report the NOX

mass emissions data and heat input data 

for such unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering May 

1, 2012 through June 30, 2012; 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.530(b), unless 

that quarter is the third or fourth quarter 

of 2011 or the first quarter of 2012, in 

which case reporting shall commence in 

the quarter covering May 1, 2012 

through June 30, 2012; 

(2) If the TR NOX Ozone Season unit 

is not subject to the Acid Rain Program 

or a TR NOX Annual emissions 

limitation, then the designated 

representative shall either: 

(i) Meet the requirements of subpart H 

of part 75 (concerning monitoring of 

NOX mass emissions) for such unit for 

the entire year and report the NOX mass 

emissions data and heat input data for 

such unit in accordance with paragraph 

(d)(1) of this section; or 

(ii) Meet the requirements of subpart 

H of part 75 for the control period 

(including the requirements in 

§ 75.74(c) of this chapter) and report 

NOX mass emissions data and heat 

input data (including the data described 

in § 75.74(c)(6) of this chapter) for such 

unit only for the control period of each 

year and report, in an electronic 

quarterly report in a format prescribed 

by the Administrator, for each calendar 

quarter beginning with: 

(A) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering May 

1, 2012 through June 30, 2012; 

(B) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.530(b), unless 

that date is not during a control period, 

in which case reporting shall commence 

in the quarter that includes May 1 

through June 30 of the first control 

period after such date; 

(3) Notwithstanding paragraphs (d)(1) 

and (2) of this section, for a unit for 

which a TR opt-in application is 

submitted and not withdrawn and is not 

yet approved or disapproved, the 

calendar quarter corresponding to the 

date specified in § 97.541(c); and 

(4) Notwithstanding paragraphs (d)(1) 

and (2) of this section, for a TR NOX


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Ozone Season opt-in unit, the calendar 

quarter corresponding to the date on 

which the TR NOX Annual opt-in unit 

enters the TR NOX Ozone Season 

Trading Program as provided in 

§ 97.541(h). 

(5) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.73(f) of this chapter. 

(6) For TR NOX Ozone Season units 

that are also subject to the Acid Rain 

Program, TR NOX Annual Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 1 Trading 

Program, quarterly reports shall include 

the applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the NOX mass emission data, 

heat input data, and other information 

required by this subpart. 

(7) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(8) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(5) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; 

(2) For a unit with add-on NOX

emission controls and for all hours 

where NOX data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate 

NOX emissions; and 

(3) For a unit that is reporting on a 

control period basis under paragraph 

(d)(2)(ii) of this section, the NOX

emission rate and NOX concentration 

values substituted for missing data 

under subpart D of part 75 of this 

chapter are calculated using only values 

from a control period and do not 

systematically underestimate NOX

emissions. 

§ 97.535 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR NOX Ozone Season unit may submit 

a petition under § 75.66 of this chapter 

to the Administrator, requesting 

approval to apply an alternative to any 

requirement of §§ 97.530 through 97.534 

or paragraph (5)(i) or (ii) of the 

definition of ‘‘owner’s share’’ in 

§ 97.502. 

(b) A petition submitted under 

paragraph (a) of this section shall 

include sufficient information for the 

evaluation of the petition, including, at 

a minimum, the following information: 

(i) Identification of each unit and 

source covered by the petition; 

(ii) A detailed explanation of why the 

proposed alternative is being suggested 

in lieu of the requirement; 

(iii) A description and diagram of any 

equipment and procedures used in the 

proposed alternative; 

(iv) A demonstration that the 

proposed alternative is consistent with 

the purposes of the requirement for 

which the alternative is proposed and 

with the purposes of this subpart and 

part 75 of this chapter and that any 

adverse effect of approving the 

alternative will be de minimis; and 

(v) Any other relevant information 

that the Administrator may require. 

(c) Use of an alternative to any 

requirement referenced in paragraph (a) 

of this section is in accordance with this 

subpart only to the extent that the 

petition is approved in writing by the 

Administrator and that such use is in 

accordance with such approval. 

§ 97.540 General requirements for TR NOX

Ozone Season opt-in units. 

(a) A TR NOX Ozone Season opt-in 

unit must be a unit that: 

(1) Is located in a State; 

(2) Is not a TR NOX Ozone Season 

unit under § 97.504; 

(3) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; and 

(4) Vents all of its emissions to a stack 

and can meet the monitoring, 

recordkeeping, and reporting 

requirements of this subpart. 

(b) A TR NOX Ozone Season opt-in 

unit shall be deemed to be a TR NOX

Ozone Season unit for purposes of 

applying this subpart, except for 

§§ 97.505, 97.511, and 97.512. 

(c) Solely for purposes of applying the 

requirements of §§ 97.513 through 

97.518 and §§ 97.530 through 97.535, a 

unit for which a TR opt-in application 

is submitted and not withdrawn and is 

not yet approved or disapproved under 

§ 97.542 shall be deemed to be a TR 

NOX Ozone Season unit. 

(d) Any TR NOX Ozone Season opt-in 

unit, and any unit for which a TR optin application is submitted and not 

withdrawn and is not yet approved or 

disapproved under § 97.542, located at 

the same source as one or more TR NOX

Ozone Season units shall have the same 

designated representative and alternate 

designated representative as such TR 

NOX Ozone Season units. 

§ 97.541 Opt-in process. 

A unit meeting the requirements for a 

TR NOX Ozone Season opt-in unit in 

§ 97.540(a) may become a TR NOX

Ozone Season opt-in unit only if, in 

accordance with this section, the 

designated representative of the unit 

submits a complete TR opt-in 

application for the unit and the 

Administrator approves the application. 

(a) Applying to opt-in. The designated 

representative of the unit may submit a 

complete TR opt-in application for the 

unit at any time, except as provided 

under § 97.542(e). A complete TR opt-in 

application shall include the following 

elements in a format prescribed by the 

Administrator: 

(1) Identification of the unit and the 

source where the unit is located, 


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including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, and unit identification 

number and type; 

(2) A certification that the unit: 

(i) Is not a TR NOX Ozone Season unit 

under § 97.504; 

(ii) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(iii) Vents all of its emissions to a 

stack; and 

(iv) Has documented heat input 

(greater than 0 mmBtu) for more than 

876 hours during the 6 months 

immediately preceding submission of 

the TR opt-in application; 

(3) A monitoring plan in accordance 

with §§ 97.530 through 97.535; 

(4) A statement that the unit, if 

approved to become a TR NOX Ozone 

Season unit under paragraph (g) of this 

section, may withdraw from the TR NOX

Ozone Season Trading Program only in 

accordance with § 97.542; 

(5) A statement that the unit, if 

approved to become a TR NOX Ozone 

Season unit under paragraph (g) of this 

section, is subject to, and the owners 

and operators of the unit must comply 

with, the requirements of § 97.543; 

(6) A complete certificate of 

representation under § 97.516 consistent 

with § 97.540, if no designated 

representative has been previously 

designated for the source that includes 

the unit; and 

(7) The signature of the designated 

representative and the date signed. 

(b) Interim review of monitoring plan. 

The Administrator will determine, on 

an interim basis, the sufficiency of the 

monitoring plan submitted under 

paragraph (a)(3) of this section. The 

monitoring plan is sufficient, for 

purposes of interim review, if the plan 

appears to contain information 

demonstrating that the NOX emission 

rate and heat input of the unit and all 

other applicable parameters are 

monitored and reported in accordance 

with §§ 97.530 through 97.535. A 

determination of sufficiency shall not be 

construed as acceptance or approval of 

the monitoring plan. 

(c) Monitoring and reporting. (1)(i) If 

the Administrator determines that the 

monitoring plan is sufficient under 

paragraph (b) of this section, the owner 

or operator of the unit shall monitor and 

report the NOX emission rate and the 

heat input of the unit and all other 

applicable parameters, in accordance 

with §§ 97.530 through 97.535, starting 

on the date of certification of the 

necessary monitoring systems under 

§§ 97.530 through 97.535 and 

continuing until the TR opt-in 

application submitted under paragraph 

(a) of this section is disapproved under 

this section or, if such TR opt-in 

application is approved, the date and 

time when the unit is withdrawn from 

the TR NOX Ozone Season Trading 

Program in accordance with § 97.542. 

(ii) The monitoring and reporting 

under paragraph (c)(1)(i) of this section 

shall cover the entire control period 

immediately before the date on which 

the unit enters the TR NOX Ozone 

Season Trading Program under 

paragraph (h) of this section, during 

which period monitoring system 

availability must not be less than 98 

percent under §§ 97.530 through 97.535 

and the unit must be in full compliance 

with any applicable State or Federal 

emissions or emissions-related 

requirements. 

(2) To the extent the NOX emissions 

rate and the heat input of the unit are 

monitored and reported in accordance 

with §§ 97.530 through 97.535 for one or 

more entire control periods, in addition 

to the control period under paragraph 

(c)(1)(ii) of this section, during which 

control periods monitoring system 

availability is not less than 98 percent 

under §§ 97.530 through 97.535 and the 

unit is in full compliance with any 

applicable State or Federal emissions or 

emissions-related requirements and 

which control periods begin not more 

than 3 years before the unit enters the 

TR NOX Ozone Season Trading Program 

under paragraph (h) of this section, such 

information shall be used as provided in 

paragraphs (e) and (f) of this section. 

(d) Statement on compliance. After 

submitting to the Administrator all 

quarterly reports required for the unit 

under paragraph (c) of this section, the 

designated representative shall submit, 

in a format prescribed by the 

Administrator, to the Administrator a 

statement that, for the years covered by 

such quarterly reports, the unit was in 

full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(e) Baseline heat input. The unit’s 

baseline heat input shall equal: 

(1) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for only one entire control 

period, in accordance with paragraph (c) 

of this section, the unit’s total heat input 

(in mmBtu) for such control period; or 

(2) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, the average of the amounts of 

the unit’s total heat input (in mmBtu) 

for such control periods. 

(f) Baseline NOX emission rate. The 

unit’s baseline NOX emission rate shall 

equal: 

(1) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for only one entire control period, in 

accordance with paragraph (c) of this 

section, the unit’s NOX emission rate (in 

lb/mmBtu) for such control period; 

(2) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit does not have addon NOX emission controls during any 

such control periods, the average of the 

amounts of the unit’s NOX emission rate 

(in lb/mmBtu) for such control periods; 

or 

(3) If the unit’s NOX emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit has add-on NOX

emission controls during any such 

control periods, the average of the 

amounts of the unit’s NOX emission rate 

(in lb/mmBtu) for such control periods 

during which the unit has add-on NOX

emission controls. 

(g) Review of TR opt-in application. 

(1) After the designated representative 

submits the complete TR opt-in 

application, quarterly reports, and 

statement required in paragraphs (a), (c), 

and (d) of this section and if the 

Administrator determines that the 

designated representative shows that the 

unit meets the requirements for a TR 

NOX Ozone Season opt-in unit in 

§ 97.540, the element certified in 

paragraph (a)(2)(iv) of this section, and 

the monitoring and reporting 

requirements of paragraph (c) of this 

section, the Administrator will issue a 

written approval of the TR opt-in 

application for the unit. The written 

approve will state the unit’s baseline 

heat input and baseline NOX emission 

rate. The Administrator will thereafter 

establish a compliance account for the 

source that includes the unit unless the 

source already has a compliance 

account. 

(2) Notwithstanding paragraphs (a) 

through (f) of this section, if, at any time 

before the TR opt-in application is 

approved under paragraph (g)(1) of this 

section, the Administrator determines 

that the unit cannot meet the 

requirements for a TR NOX Ozone 

Season opt-in unit in § 97.540, the 

element certified in paragraph (a)(2)(iv) 

of this section, or the monitoring and 

reporting requirements in paragraph (c) 

of this section, the Administrator will 

issue a written disapproval of the TR 

opt-in application for the unit. 


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(h) Date of entry into TR NOX Ozone 

Season Trading Program. A unit for 

which a TR opt-in application is 

approved under paragraph (g)(1) of this 

section shall become a TR NOX Ozone 

Season opt-in unit, and a TR NOX

Ozone Season unit, effective as of the 

later of May 1, 2012 or May 1 of the first 

control period during which such 

approval is issued. 

§ 97.542 Withdrawal of TR NOX Ozone 

Season opt-in unit from TR NOX Ozone 

Season Trading Program. 

A TR NOX Ozone Season opt-in unit 

may withdraw from the TR NOX Ozone 

Season Trading Program only if, in 

accordance with this section, the 

designated representative of the unit 

submits a request to withdraw the unit 

and the Administrator issues a written 

approval of the request. 

(a) Requesting withdrawal. In order to 

withdraw the TR NOX Ozone Season 

opt-in unit from the TR NOX Ozone 

Season Trading Program, the designated 

representative of the unit shall submit to 

the Administrator a request to withdraw 

the unit effective as of midnight of 

September 30 of a specified calendar 

year, which date must be at least 4 years 

after September 30 of the year of the 

unit’s entry into the TR NOX Ozone 

Season Trading Program under 

§ 97.541(h). The request shall be in a 

format prescribed by the Administrator 

and shall be submitted no later than 90 

days before the requested effective date 

of withdrawal. 

(b) Conditions for withdrawal. Before 

a TR NOX Ozone Season opt-in unit 

covered by the request to withdraw may 

withdraw from the TR NOX Ozone 

Season Trading Program, the following 

conditions must be met: 

(1) For the control period ending on 

the date on which the withdrawal is to 

be effective, the source that includes the 

TR NOX Ozone Season opt-in unit must 

meet the requirement to hold TR NOX

Ozone Season allowances under 

§§ 97.524 and 97.525 and cannot have 

any excess emissions. 

(2) After the requirement under 

paragraph (b)(1) of this section is met, 

the Administrator will deduct from the 

compliance account of the source that 

includes the TR NOX Ozone Season optin unit TR NOX Ozone Season 

allowances equal in amount to and 

allocated for the same or a prior control 

period as any TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season opt-in unit under 

§ 97.544 for any control period after the 

date on which the withdrawal is to be 

effective. If there are no other TR NOX

Ozone Season units at the source, the 

Administrator will close the compliance 

account, and the owners and operators 

of the TR NOX Ozone Season opt-in unit 

may submit a TR NOX Ozone Season 

allowance transfer for any remaining TR 

NOX Ozone Season allowances to 

another Allowance Management System 

account in accordance §§ 97.522 and 

97.523. 

(c) Approving withdrawal. (1) After 

the requirements for withdrawal under 

paragraphs (a) and (b) of this section are 

met (including deduction of the full 

amount of TR NOX Ozone Season 

allowances required), the Administrator 

will issue a written approval of the 

request to withdraw, which will become 

effective as of midnight on September 

30 of the calendar year for which the 

withdrawal was requested. The unit 

covered by the request shall continue to 

be a TR NOX Ozone Season opt-in unit 

until the effective date of the 

withdrawal and shall comply with all 

requirements under the TR NOX Ozone 

Season Trading Program concerning any 

control periods for which the unit is a 

TR NOX Ozone Season opt-in unit, even 

if such requirements arise or must be 

complied with after the withdrawal 

takes effect. 

(2) If the requirements for withdrawal 

under paragraphs (a) and (b) of this 

section are not met, the Administrator 

will issue a written disapproval of the 

request to withdraw. The unit covered 

by the request shall continue to be a TR 

NOX Ozone Season opt-in unit. 

(d) Reapplication upon failure to meet 

conditions of withdrawal. If the 

Administrator disapproves the request 

to withdraw, the designated 

representative of the unit may submit 

another request to withdraw in 

accordance with paragraphs (a) and (b) 

of this section. 

(e) Ability to reapply to the TR NOX

Ozone Season Trading Program. Once a 

TR NOX Ozone Season opt-in unit 

withdraws from the TR NOX Ozone 

Season Trading Program, the designated 

representative may not submit another 

opt-in application under § 97.541 for 

such unit before the date that is 4 years 

after the date on which the withdrawal 

became effective. 

§ 97.543 Change in regulatory status. 

(a) Notification. If a TR NOX Ozone 

Season opt-in unit becomes a TR NOX

Ozone Season unit under § 97.504, then 

the designated representative of the unit 

shall notify the Administrator in writing 

of such change in the TR NOX Ozone 

Season opt-in unit’s regulatory status, 

within 30 days of such change. 

(b) Administrator’s actions. (1) If a TR 

NOX Ozone Season opt-in unit becomes 

a TR NOX Ozone Season unit under 

§ 97.504, the Administrator will deduct, 

from the compliance account of the 

source that includes the TR NOX Ozone 

Season opt-in unit that becomes a TR 

NOX Ozone Season unit under § 97.504, 

TR NOX Ozone Season allowances equal 

in amount to and allocated for the same 

or a prior control period as: 

(i) Any TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season opt-in unit under 

§ 97.544 for any control period starting 

after the date on which the TR NOX

Ozone Season opt-in unit becomes a TR 

NOX Ozone Season unit under § 97.504; 

and 

(ii) If the date on which the TR NOX

Ozone Season opt-in unit becomes a TR 

NOX Ozone Season unit under § 97.504 

is not September 30, the TR NOX Ozone 

Season allowances allocated to the TR 

NOX Ozone Season opt-in unit under 

§ 97.544 for the control period that 

includes the date on which the TR NOX

Ozone Season opt-in unit becomes a TR 

NOX Ozone Season unit under 

§ 97.504— 

(A) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

NOX Ozone Season opt-in unit becomes 

a TR NOX Ozone Season unit under 

§ 97.504, divided by the total number of 

days in the control period, and 

(B) Rounded to the nearest allowance. 

(2) The designated representative 

shall ensure that the compliance 

account of the source that includes the 

TR NOX Ozone Season opt-in unit that 

becomes a TR NOX Ozone Season unit 

under § 97.504 contains the TR NOX

Ozone Season allowances necessary for 

completion of the deduction under 

paragraph (b)(1) of this section. 

(3)(i) For control periods starting after 

the date on which the TR NOX Ozone 

Season opt-in unit becomes a TR NOX

Ozone Season unit under § 97.504, the 

TR NOX Ozone Season opt-in unit will 

be allocated TR NOX Ozone Season 

allowances in accordance with § 97.512. 

(ii) If the date on which the TR NOX

Ozone Season opt-in unit becomes a TR 

NOX Ozone Season unit under § 97.504 

is not September 30, the following 

amount of TR NOX Ozone Season 

allowances will be allocated to the TR 

NOX Ozone Season opt-in unit (as a TR 

NOX Ozone Season unit) in accordance 

with § 97.512 for the control period that 

includes the date on which the TR NOX

Ozone Season opt-in unit becomes a TR 

NOX Ozone Season unit under § 97.504: 

(A) The amount of TR NOX Ozone 

Season allowances otherwise allocated 

to the TR NOX Ozone Season opt-in unit 

(as a TR NOX Ozone Season unit) in 

accordance with § 97.512 for the control 

period; 


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(B) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

NOX Ozone Season opt-in unit becomes 

a TR NOX Ozone Season unit under 

§ 97.504, divided by the total number of 

days in the control period; and 

(C) Rounded to the nearest allowance. 

§ 97.544 TR NOX Ozone Season allowance 

allocations to TR NOX Ozone Season opt-in 

units. 

(a) Timing requirements. (1) When the 

TR opt-in application is approved for a 

unit under § 97.541(g), the 

Administrator will issue TR NOX Ozone 

Season allowances and allocate them to 

the unit for the control period in which 

the unit enters the TR NOX Ozone 

Season Trading Program under 

§ 97.541(h), in accordance with 

paragraph (b) of this section. 

(2) By no later than July 30 of the 

control period after the control period in 

which a TR NOX Ozone Season opt-in 

unit enters the TR NOX Ozone Season 

Trading Program under § 97.541(h) and 

July 30 of each year thereafter, the 

Administrator will issue TR NOX Ozone 

Season allowances and allocate them to 

the TR NOX Ozone Season opt-in unit 

for the control period that includes such 

allocation deadline and in which the 

unit is a TR NOX Ozone Season opt-in 

unit, in accordance with paragraph (b) 

of this section. 

(b) Calculation of allocation. For each 

control period for which a TR NOX

Ozone Season opt-in unit is to be 

allocated TR NOX Ozone Season 

allowances, the Administrator will issue 

and allocate TR NOX Ozone Season 

allowances in accordance with the 

following procedures: 

(1) The heat input (in mmBtu) used 

for calculating the TR NOX Ozone 

Season allowance allocation will be the 

lesser of: 

(i) The TR NOX Ozone Season opt-in 

unit’s baseline heat input determined 

under § 97.541(g); or 

(ii) The TR NOX Ozone Season opt-in 

unit’s heat input, as determined in 

accordance with §§ 97.530 through 

97.535, for the immediately prior 

control period, except when the 

allocation is being calculated for the 

control period in which the TR NOX

Ozone Season opt-in unit enters the TR 

NOX Ozone Season Trading Program 

under § 97.541(h). 

(2) The NOX emission rate (in lb/ 

mmBtu) used for calculating TR NOX

Ozone Season allowance allocations 

will be the lesser of: 

(i) The TR NOX Ozone Season opt-in 

unit’s baseline NOX emission rate (in lb/ 

mmBtu) determined under § 97.541(g) 

and multiplied by 70 percent; or 

(ii) The most stringent State or 

Federal NOX emissions limitation 

applicable to the TR NOX Ozone Season 

opt-in unit at any time during the 

control period for which TR NOX Ozone 

Season allowances are to be allocated. 

(3) The Administrator will issue TR 

NOX Ozone Season allowances and 

allocate them to the TR NOX Ozone 

Season opt-in unit in an amount 

equaling the heat input under paragraph 

(b)(1) of this section, multiplied by the 

NOX emission rate under paragraph 

(b)(2) of this section, divided by 2,000 

lb/ton, and rounded to the nearest 

allowance. 

(c) Recordation. (1) The Administrator 

will record, in the compliance account 

of the source that includes the TR NOX

Ozone Season opt-in unit, the TR NOX

Ozone Season allowances allocated to 

the TR NOX Ozone Season opt-in unit 

under paragraph (a)(1) of this section. 

(2) By September 1 of the control 

period after the control period in which 

a TR NOX Ozone Season opt-in unit 

enters the TR NOX Ozone Season 

Trading Program under § 97.541(h) and 

September 1 of each year thereafter, the 

Administrator will record, in the 

compliance account of the source that 

includes the TR NOX Ozone Season optin unit, the TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season opt-in unit under 

paragraph (a)(2) of this section. 

37. Part 97 is amended by adding 

subpart CCCCC to read as follows: 

Subpart CCCCC—TR SO2 Group 1 Trading 

Program 

Sec. 

97.601 Purpose. 

97.602 Definitions. 

97.603 Measurements, abbreviations, and 

acronyms. 

97.604 Applicability. 

97.605 Retired unit exemption. 

97.606 Standard requirements. 

97.607 Computation of time. 

97.608 Administrative appeal procedures. 

97.609 [Reserved] 

97.610 State SO2 Group 1 trading budgets, 

new-unit set- asides, and variability 

limits. 

97.611 Timing requirements for TR SO2

Group 1 allowance allocations. 

97.612 TR SO2 Group 1 allowance 

allocations for new units. 

97.613 Authorization of designated 

representative and alternate designated 

representative. 

97.614 Responsibilities of designated 

representative and alternate designated 

representative. 

97.615 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.616 Certificate of representation. 

97.617 Objections concerning designated 

representative and alternate designated 

representative. 

97.618 Delegation by designated 

representative and alternate designated 

representative. 

97.619 [Reserved] 

97.620 Establishment of Allowance 

Management System accounts. 

97.621 Recordation of TR SO2 Group 1 

allowance allocations. 

97.622 Submission of TR SO2 Group 1 

allowance transfers. 

97.623 Recordation of TR SO2 Group 1 

allowance transfers. 

97.624 Compliance with TR SO2 Group 1 

emissions limitation. 

97.625 Compliance with TR SO2 Group 1 

assurance provisions. 

97.626 Banking. 

97.627 Account error. 

97.628 Administrator’s action on 

submissions. 

97.629 [Reserved] 

97.630 General monitoring, recordkeeping, 

and reporting requirements. 

97.631 Initial monitoring system 

certification and recertification 

procedures. 

97.632 Monitoring system out-of-control 

periods. 

97.633 Notifications concerning 

monitoring. 

97.634 Recordkeeping and reporting. 

97.635 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

97.640 General requirements for TR SO2

Group 1 opt-in units. 

97.641 Opt-in process. 

97.642 Withdrawal of TR SO2 Group 1 optin unit from TR SO2 Group 1 Trading 

Program. 

97.643 Change in regulatory status. 

97.644 TR SO2 Group 1 allowance 

allocations to TR SO2 Group 1 opt-in 

units. 

Subpart CCCCC—TR SO2 Group 1 

Trading Program 

§ 97.601 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) SO2 Group 1 

Trading Program, under section 110 of 

the Clean Air Act and § 52.38(b) of this 

chapter, as a means of mitigating 

interstate transport of fine particulates 

and nitrogen oxides. 

§ 97.602 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor) of the United 


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States Environmental Protection 

Agency, the Administrator’s duly 

authorized representative under this 

subpart. 

Allocate or allocation means, with 

regard to TR SO2 Group 1 allowances, 

the determination by the Administrator 

of the amount of such TR SO2 Group 1 

allowances to be initially credited to a 

TR SO2 Group 1 source or a new unit 

set-aside. 

Allowable SO2 emission rate means, 

with regard to a unit, the SO2 emission 

rate limit that is applicable to the unit 

and covers the longest averaging period 

not exceeding one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR SO2

Group 1 allowances under the TR SO2

Group 1 Trading Program. Such 

allowances are allocated, held, 

deducted, or transferred only as whole 

allowances. The Allowance 

Management System is a component of 

the CAMD Business System, which is 

the system used by the Administrator to 

handle TR SO2 Group 1 allowances and 

data related to SO2 emissions. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

SO2 Group 1 allowances. 

Allowance transfer deadline means, 

for a control period, midnight of March 

1 (if it is a business day), or midnight 

of the first business day thereafter (if 

March 1 is not a business day), 

immediately after such control period 

and is the deadline by which a TR SO2

Group 1 allowance transfer must be 

submitted for recordation in a TR SO2

Group 1 source’s compliance account in 

order to be available for use in 

complying with the source’s TR SO2

Group 1 Annual emissions limitation for 

such control period in accordance with 

§ 97.624. 

Alternate designated representative 

means, for a TR SO2 Group 1 source and 

each TR SO2 Group 1 unit at the source, 

the natural person who is authorized by 

the owners and operators of the source 

and all such units at the source, in 

accordance with this subpart, to act on 

behalf of the designated representative 

in matters pertaining to the TR SO2

Group 1 Trading Program. If the TR SO2

Group 1 source is also subject to the 

Acid Rain Program, TR NOX Annual 

Season Trading Program, or TR NOX

Ozone Season Trading Program, then 

this natural person shall be the same 

natural person as the alternate 

designated representative as defined in 

§ 72.2 of this chapter, § 97.402, or 

§ 97.502 respectively. 

Authorized account representative 

means, with regard to a general account, 

the natural person who is authorized, in 

accordance with this subpart, to transfer 

and otherwise dispose of TR SO2 Group 

1 allowances held in the general 

account and, with regard to a TR SO2

Group 1 source’s compliance account, 

the designated representative of the 

source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 

(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

Certifying official means a natural 

person who is: 

(1) For a corporation, a president, 

secretary, treasurer, or vice-president or 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy or 

decision-making functions for the 

corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Coal-fired means combusting any 

amount of coal or coal-derived fuel, 

alone or in combination with any 

amount of any other fuel, during 1990 

or any year thereafter. 

Cogeneration system means an 

integrated group, at a source, of 

equipment (including a boiler, or 

combustion turbine, and a steam turbine 

generator) designed to produce useful 

thermal energy for industrial, 

commercial, heating, or cooling 

purposes and electricity through the 

sequential use of energy. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine— 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing during the later of 1990 

or the 12-month period starting on the 

date that the unit first produces 

electricity and during each calendar 

year after the later of 1990 or the 

calendar year in which the unit first 

produces electricity— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle unit, useful 

power not less than 45 percent of total 

energy input; 

(3) Provided that the total energy 

input under paragraphs (2)(i)(B) and 

(2)(ii) of this definition shall equal the 

unit’s total energy input from all fuel, 

except biomass if the unit is a boiler; 

and 

(4) Provided that, if a topping-cycle 

unit is operated as part of a cogeneration 

system during a calendar year and the 

cogeneration system meets on a systemwide basis the requirement in paragraph 


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(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such 

requirement during that calendar year. 

Combustion turbine means an 

enclosed device comprising: 

(1) If the device is simple cycle, a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the device is combined cycle, 

the equipment described in paragraph 

(1) of this definition and any associated 

duct burner, heat recovery steam 

generator, and steam turbine. 

Commence commercial operation 

means, with regard to a unit: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 97.605. 

(i) For a unit that is a TR SO2 Group 

1 unit under § 97.604 on the later of 

November 15, 1990 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit that is a TR SO2 Group 

1 unit under § 97.604 on the later of 

November 15, 1990 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source, such date shall remain the 

replaced unit’s date of commencement 

of commercial operation, and the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 97.605, for a unit that is not a TR 

SO2 Group 1 unit under § 97.604 on the 

later of November 15, 1990 or the date 

the unit commences commercial 

operation as defined in introductory text 

of paragraph (1) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a TR SO2

Group 1 unit under § 97.604. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that subsequently undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source), 

such date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that is subsequently replaced by a 

unit at the same source, such date shall 

remain the replaced unit’s date of 

commencement of commercial 

operation, and the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

Commence operation means, with 

regard to a unit: 

(1) To have begun any mechanical, 

chemical, or electronic process, 

including start-up of the unit’s 

combustion chamber. 

(2) For a unit that undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source) 

after the date the unit commences 

operation as defined in paragraph (1) of 

this definition, such date shall remain 

the date of commencement of operation 

of the unit, which shall continue to be 

treated as the same unit. 

(3) For a unit that is replaced by a unit 

at the same source after the date the unit 

commences operation as defined in 

paragraph (1) of this definition, such 

date shall remain the replaced unit’s 

date of commencement of operation, 

and the replacement unit shall be 

treated as a separate unit with a separate 

date for commencement of operation as 

defined in paragraph (1), (2), or (3) of 

this definition as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR SO2 Group 1 

source under this subpart, in which any 

TR SO2 Group 1 allowance allocations 

for the TR SO2 Group 1 units at the 

source are recorded and in which are 

held any TR SO2 Group 1 allowances 

available for use for a control period in 

complying with the source’s TR SO2

Group 1 emissions limitation in 

accordance with § 97.624 and the TR 

SO2 Group 1 assurance provisions in 

accordance with § 97.625. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of SO2 emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.630 

through 97.635. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A SO2 monitoring system, 

consisting of a SO2 pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of SO2

emissions, in parts per million (ppm); 

(3) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(4) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(5) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting January 1 of a calendar year, 

except as provided in § 97.606(c)(3), and 

ending on December 31 of the same 

year, inclusive. 

Designated representative means, for 

a TR SO2 Group 1 source and each TR 

SO2 Group 1 unit at the source, the 

natural person who is authorized by the 

owners and operators of the source and 

all such units at the source, in 

accordance with this subpart, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

TR SO2 Group 1 Trading Program. If the 

TR SO2 Group 1 source is also subject 

to the Acid Rain Program, TR NOX

Annual Trading Program, or TR NOX

Ozone Season Trading Program, then 

this natural person shall be the same 

natural person as the designated 

representative, as defined in § 72.2 of 

this chapter, § 97.402, or § 97.502 

respectively. 


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Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart. 

Excess emissions means any ton of 

SO2 emitted from the TR SO2 Group 1 

units at a TR SO2 Group 1 source during 

a control period that exceeds the TR SO2

Group 1 emissions limitation for the 

source. 

Fossil fuel means— 

(1) Natural gas, petroleum, coal, or 

any form of solid, liquid, or gaseous fuel 

derived from such material; or 

(2) For purposes of applying 

§§ 97.604(b)(2)(i)(B), 97.604(b)(2)(ii)(B), 

and 97.604(b)(2)(iii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 1990 or any calendar year 

thereafter. 

Fuel oil means any petroleum-based 

fuel (including diesel fuel or petroleum 

derivatives such as oil tar) and any 

recycled or blended petroleum products 

or petroleum by-products used as a fuel 

whether in a liquid, solid, or gaseous 

state. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a unit, electricity made 

available for use, including any such 

electricity used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Heat input means, with regard to a 

unit for a specified period of time, the 

product (in mmBtu/time) of the gross 

calorific value of the fuel (in mmBtu/lb) 

multiplied by the fuel feed rate into a 

combustion device (in lb of fuel/time), 

as measured, recorded, and reported to 

the Administrator by the designated 

representative and as modified by the 

Administrator in accordance with this 

subpart and excluding the heat derived 

from preheated combustion air, 

recirculated flue gases, or exhaust. 

Heat input rate means the amount of 

heat input (in mmBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means 

the maximum amount of fuel per hour 

(in Btu/hr) that a unit is capable of 

combusting on a steady state basis as of 

the initial installation of the unit as 

specified by the manufacturer of the 

unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as of such 

installation as specified by the 

manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as of such completion as 

specified by the person conducting the 

physical change. 

Newly affected TR SO2 Group 1 unit 

means a unit that was not a TR SO2

Group 1 unit when it began operating 

but that thereafter becomes a TR SO2

Group 1 unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means any person who 

operates, controls, or supervises a TR 

SO2 Group 1 unit or a TR SO2 Group 1 

source and shall include, but not be 

limited to, any holding company, utility 

system, or plant manager of such a unit 

or source. 

Owner means, with regard to a TR SO2

Group 1 source or a TR SO2 Group 1 

unit at a source respectively, any of the 

following persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR SO2

Group 1 unit at the source or the TR SO2

Group 1 unit; 

(2) Any holder of a leasehold interest 

in a TR SO2 Group 1 unit at the source 

or the TR SO2 Group 1 unit, provided 

that, unless expressly provided for in a 

leasehold agreement, ‘‘owner’’ shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such TR 

SO2 Group 1 unit; 

(3) Any purchaser of power from a TR 

SO2 Group 1 unit at the source or the 

TR SO2 Group 1 unit under a life-of-theunit, firm power contractual 

arrangement; 

(4) Provided that, for purposes of 

applying the TR SO2 Group 1 assurance 

provisions in §§ 97.606(c)(2) and 97.625, 

if one or more owners (as defined in 

paragraphs (1) through (3) of this 

definition) of one or more TR SO2 Group 

1 units in a State are wholly owned by 

another, common owner, all such 

owners shall be treated collectively as a 

single owner in the State. 

Owner’s assurance level means: 

(1) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.606(c)(2)(iii)(A) and not as 

described in § 97.606(c)(2)(iii)(B), the 

owner’s share of the State SO2 Group 1 

trading budget with the one-year 

variability limit for the State for such 

control period; or 

(2) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.606(c)(2)(iii)(B), the owner’s share 

of the State SO2 Group 1 trading budget 

with the three-year variability limit for 

the State for such control period. 

Owner’s share means: 

(1) With regard to a total amount of 

SO2 emissions from all TR SO2 Group 1 

units in a State during a control period, 

the total tonnage of SO2 emissions 

during such control period from all of 

the owner’s TR SO2 Group 1 units in the 

State; 

(2) With regard to a State SO2 Group 

1 trading budget with a one-year 

variability limit for a control period, the 


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amount (rounded to the nearest 

allowance) equal to the total amount of 

TR SO2 Group 1 allowances allocated 

for such control period to all of the 

owner’s TR SO2 Group 1 units in the 

State, multiplied by the sum of the State 

SO2 Group 1 trading budget under 

§ 97.610(a) and the State’s one-year 

variability limit under § 97.610(b) and 

divided by such State SO2 Group 1 

trading budget; 

(3) With regard to a State SO2 Group 

1 trading budget with a three-year 

variability limit for a control period, the 

amount (rounded to the nearest 

allowance) equal to the total amount of 

TR SO2 Group 1 allowances allocated 

for such control period to all of the 

owner’s TR SO2 Group 1 units in the 

State, multiplied by the sum of the State 

SO2 Group 1 trading budget under 

§ 97.610(a) and the State’s three-year 

variability limit under § 97.610(b) and 

divided by such State SO2 Group 1 

trading budget; 

(4) Provided that, in the case of a unit 

with more than one owner, the amount 

of tonnage of SO2 emissions and of TR 

SO2 Group 1 allowances allocated for a 

control period, with regard to such unit, 

used in determining each owner’s share 

shall be the amount (rounded to the 

nearest ton and the nearest allowance) 

equal to the unit’s SO2 emissions and 

allocation of such allowances, 

respectively, for such control period 

multiplied by the percentage of 

ownership in the unit that the owner’s 

legal, equitable, leasehold, or 

contractual reservation or entitlement in 

the unit comprises as of December 31 of 

such control period; 

(5) Provided that, where two or more 

units emit through a common stack that 

is the monitoring location from which 

SO2 mass emissions are reported for a 

control period for a year, the amount of 

tonnage of each unit’s SO2 emissions 

used in determining each owner’s share 

for such control period shall be: 

(i) The amount (rounded to the 

nearest ton) of SO2 emissions reported 

at the common stack multiplied by the 

quotient of such unit’s heat input for 

such control period divided by the total 

heat input reported from the common 

stack for such control period; 

(ii) An amount determined in 

accordance with a methodology that the 

Administrator determines is consistent 

with the purposes of this definition and 

whose adverse effect (if any) the 

Administrator determines will be de 

minimis; or 

(iii) An amount approved by the 

Administrator in response to a petition 

for an alternative requirement submitted 

in accordance with § 97.635; and 

(6) Provided that, in the case of a unit 

that operates during, but is allocated no 

TR SO2 Group 1 allowances for, a 

control period, the unit shall be treated, 

solely for purposes of this definition, as 

being allocated an amount (rounded to 

the nearest allowance) of TR SO2 Group 

1 allowances for such control period 

equal to the lesser of— 

(i) The unit’s allowable SO2 emission 

rate (in lb per MWe) applicable to such 

control period, multiplied by a capacity 

factor of 0.84 (if the unit is a coal-fired 

boiler), 0.15 (if the unit is a simple 

combustion turbine), or 0.66 (if the unit 

is a combined cycle turbine), multiplied 

by the unit’s maximum hourly load as 

reported in accordance with this subpart 

and by 8,760 hours/control period, and 

divided by 2,000 lb/ton; or 

(ii) For a unit listed in appendix A to 

this subpart, the sum of the unit’s SO2

emissions in the control period in the 

last three years during which the unit 

operated during the control period, 

divided by three. 

Permanently retired means, with 

regard to a unit, a unit that is 

unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Potential electrical output capacity 

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/ 

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR SO2 Group 1 

allowances, the moving of TR SO2

Group 1 allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) For a topping-cycle unit, the use 

of reject heat from electricity production 

in a useful thermal energy application 

or process; or 

(2) For a bottoming-cycle unit, the use 

of reject heat from useful thermal energy 

application or process in electricity 

production. 

Serial number means, for a TR SO2

Group 1 allowance, the unique 

identification number assigned to each 

TR SO2 Group 1 allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States or the 

District of Columbia that is subject to 

the TR SO2 Group 1 Trading Program 

pursuant to § 52.38(b) of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline shall 

be determined by the date of dispatch, 

transmission, or mailing and not the 

date of receipt. 

Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means total energy 

of all forms supplied to a unit, 

excluding energy produced by the unit. 

Each form of energy supplied shall be 

measured by the lower heating value of 

that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55(W + 9H) 

Where: 

LHV = lower heating value of the form of 

energy in Btu/lb, 


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HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means the sum of 

useful power and useful thermal energy 

produced by the unit. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with subpart AAAAA and 

52.37(a) of this chapter, as a means of 

mitigating interstate transport of fine 

particulates and NOX.

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established by the 

Administrator in accordance with 

subpart BBBBB of this part and 52.37(b) 

of this chapter, as a means of mitigating 

interstate transport of ozone and NOX.

TR SO2 Group 1 allowance means a 

limited authorization issued and 

allocated by the Administrator under 

this subpart to emit one ton of SO2

during a control period of the specified 

calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the TR 

SO2 Group 1 Trading Program. 

TR SO2 Group 1 allowance deduction 

or deduct TR SO2 Group 1 allowances 

means the permanent withdrawal of TR 

SO2 Group 1 allowances by the 

Administrator from a compliance 

account, e.g., in order to account for 

compliance with the TR SO2 Group 1 

emissions limitation or assurance 

provisions. 

TR SO2 Group 1 allowances held or 

hold TR SO2 Group 1 allowances means 

the TR SO2 Group 1 allowances treated 

as included in an Allowance 

Management System account as of a 

specified point in time because at that 

time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR SO2 Group 1 allowance 

transfer in accordance with this subpart; 

and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR SO2 Group 1 

allowance transfer in accordance with 

this subpart. 

TR SO2 Group 1 emissions limitation 

means, for a TR SO2 Group 1 source, the 

tonnage of SO2 emissions authorized in 

a control period by the TR SO2 Group 

1 allowances available for deduction for 

the source under § 97.624(a) for such 

control period. 

TR SO2 Group 1 source means a 

source that includes one or more TR 

SO2 Group 1 units. 

TR SO2 Group 1 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with this subpart and 

52.38(b) of this chapter, as a means of 

mitigating interstate transport of fine 

particulates and SO2.

TR SO2 Group 1 unit means a unit 

that is subject to the TR SO2 Group 1 

Trading Program under § 97.604. 

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired 

combustion turbine, or other stationary, 

fossil-fuel-fired combustion device. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means electricity or 

mechanical energy that a unit makes 

available for use, excluding any such 

energy used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.603 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.604 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State shall 

be TR SO2 Group 1 units, and any 

source that includes one or more such 

units shall be a TR SO2 Group 1 source, 

subject to the requirements of this 

subpart: Any stationary, fossil-fuel-fired 

boiler or stationary, fossil-fuel-fired 

combustion turbine serving at any time, 

since the later of November 15, 1990 or 

the start-up of the unit’s combustion 

chamber, a generator with nameplate 

capacity of more than 25 MWe 

producing electricity for sale. 

(2) If a stationary boiler or stationary 

combustion turbine that, under 

paragraph (a)(1) of this section, is not a 

TR SO2 Group 1 unit begins to combust 

fossil fuel or to serve a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale, the 

unit shall become a TR SO2 Group 1 

unit as provided in paragraph (a)(1) of 

this section on the first date on which 

it both combusts fossil fuel and serves 

such generator. 

(b) Any unit in a State that otherwise 

is a TR SO2 Group 1 unit under 

paragraph (a) of this section and that 

meets the requirements set forth in 

paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) 

of this section shall not be a TR SO2

Group 1 unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

during the later of 1990 or the 12-month 

period starting on the date the unit first 

produces electricity and continuing to 

qualify as a cogeneration unit; and 

(B) Not serving at any time, since the 

later of November 15, 1990 or the startup of the unit’s combustion chamber, a 

generator with nameplate capacity of 

more than 25 MWe supplying in any 

calendar year more than one-third of the 

unit’s potential electric output capacity 

or 219,000 MWh, whichever is greater, 

to any utility power distribution system 

for sale. 

(ii) If a unit qualifies as a cogeneration 

unit during the later of 1990 or the 12- 

month period starting on the date the 

unit first produces electricity and meets 

the requirements of paragraphs (b)(1)(i) 

of this section for at least one calendar 

year, but subsequently no longer meets 

such qualification and requirements, the 

unit shall become a TR SO2 Group 1 

unit starting on the earlier of January 1 

after the first calendar year during 

which the unit first no longer qualifies 

as a cogeneration unit or January 1 after 

the first calendar year during which the 

unit no longer meets the requirements of 

paragraph (b)(1)(i)(B) of this section. 


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(2)(i) Any unit commencing operation 

before January 1, 1985: 

(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average annual fuel 

consumption of fossil fuel for 1985– 

1987 less than 20 percent (on a Btu 

basis) and an average annual fuel 

consumption of fossil fuel for any 3 

consecutive calendar years after 1990 

less than 20 percent (on a Btu basis). 

(ii) Any unit commencing operation 

on or after January 1, 1985: 

(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average annual fuel 

consumption of fossil fuel for the first 

3 calendar years of operation less than 

20 percent (on a Btu basis) and an 

average annual fuel consumption of 

fossil fuel for any 3 consecutive 

calendar years after 1990 less than 20 

percent (on a Btu basis). 

(iii) If a unit qualifies as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and meets the requirements 

of paragraph (b)(2)(i) or (ii) of this 

section for at least 3 consecutive 

calendar years, but subsequently no 

longer meets such qualification and 

requirements, the unit shall become a 

TR SO2 Group 1 unit starting on the 

earlier of January 1 after the first 

calendar year during which the unit first 

no longer qualifies as a solid waste 

incineration unit or January 1 after the 

first 3 consecutive calendar years after 

1990 for which the unit has an average 

annual fuel consumption of fossil fuel of 

20 percent or more. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 

may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR SO2 Group 

1 Trading Program to the unit or other 

equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 

equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the petition shall 

include the following certification 

statement, signed by the certifying 

official: ‘‘I am authorized to make this 

submission on behalf of the owners and 

operators of the unit or other equipment 

for which the submission is made. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) Response. The Administrator will 

issue a written response to the petition 

and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR SO2 Group 

1 Trading Program to the unit or other 

equipment shall be binding on any 

permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.605 Retired unit exemption. 

(a)(1) Any TR SO2 Group 1 unit that 

is permanently retired and is not a TR 

SO2 Group 1 opt-in unit shall be exempt 

from § 97.606(b) and (c)(1), § 97.624, 

and §§ 97.630 through 97.635. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR SO2

Group 1 unit is permanently retired. 

Within 30 days of the unit’s permanent 

retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any SO2, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

SO2 Group 1 Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 

§ 97.606 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.613 through 97.618. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each TR 

SO2 Group 1 source and each TR SO2

Group 1 unit at the source shall comply 

with the monitoring, reporting, and 

recordkeeping requirements of §§ 97.630 

through 97.635. 

(2) The emissions data determined in 

accordance with §§ 97.630 through 

97.635 shall be used to calculate 

allocations of TR SO2 Group 1 

allowances under §§ 97.611(a)(2) and (b) 

and 97.612 and to determine 

compliance with the TR SO2 Group 1 

emissions limitation and assurance 

provisions under paragraph (c) of this 

section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.630 through 97.635 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) SO2 emissions requirements—(1) 

TR SO2 Group 1 emissions limitation. (i) 

As of the allowance transfer deadline for 


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45424 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

a control period, the owners and 

operators of each TR SO2 Group 1 

source and each TR SO2 Group 1 unit 

at the source shall hold, in the source’s 

compliance account, TR SO2 Group 1 

allowances available for deduction for 

such control period under § 97.624(a) in 

an amount not less than the tons of total 

SO2 emissions for such control period 

from all TR SO2 Group 1 units at the 

source. 

(ii) If a TR SO2 Group 1 source emits 

SO2 during any control period in excess 

of the TR SO2 Group 1 emissions 

limitation set forth in paragraph (c)(1)(i) 

of this section, then: 

(A) The owners and operators of the 

source and each TR SO2 Group 1 unit 

at the source shall hold the TR SO2

Group 1 allowances required for 

deduction under § 97.624(d) and pay 

any fine, penalty, or assessment or 

comply with any other remedy imposed, 

for the same violations, under the Clean 

Air Act; and 

(B) Each ton of such excess emissions 

and each day of such control period 

shall constitute a separate violation of 

this subpart and the Clean Air Act. 

(2) TR SO2 Group 1 assurance 

provisions. (i) If the total amount of SO2

emissions from all TR SO2 Group 1 

units in a State during a control period 

in 2014 or any year thereafter exceeds 

the State assurance level as described in 

paragraph (c)(2)(iii) of this section, then 

each owner whose share of such SO2

emissions during such control period 

exceeds the owner’s assurance level for 

the State and such control period shall 

hold, in a compliance account 

designated by the owner in accordance 

with § 97.625(b)(4)(ii), TR SO2 Group 1 

allowances available for deduction for 

such control period under § 97.625(a) in 

an amount equal to the product, as 

determined by the Administrator in 

accordance with § 97.625(b), of 

multiplying— 

(A) The quotient (rounded to the 

nearest whole number) of the amount by 

which the owner’s share of such SO2

emissions exceeds the owner’s 

assurance level divided by the sum of 

the amounts, determined for all such 

owners, by which each owner’s share of 

such SO2 emissions exceeds that 

owner’s assurance level; and 

(B) The amount by which total SO2

emissions for all TR SO2 Group 1 units 

in the State for such control period 

exceed the State assurance level as 

determined in accordance with 

paragraph (c)(2)(iii) of this section. 

(ii) The owner shall hold the TR SO2

Group 1 allowances required under 

paragraph (c)(2)(i) of this section, as of 

midnight of November 1 (if it is a 

business day), or midnight of the first 

business day thereafter (if November 1 

is not a business day), immediately after 

such control period. 

(iii) The total amount of SO2

emissions from all TR SO2 Group 1 

units in a State during a control period 

in 2014 or any year thereafter exceeds 

the State assurance level: 

(A) If such total amount of SO2

emissions exceeds the sum, for such 

control period, of the State SO2 Group 

1 trading budget and the State’s oneyear variability limit under § 97.610(b); 

or 

(B) If, with regard to a control period 

in 2016 or any year thereafter, the sum, 

divided by three, of such total amount 

of SO2 emissions and the total amounts 

of SO2 emissions from all TR SO2 Group 

1 units in the State during the control 

periods in the immediately preceding 

two years exceeds the sum, for such 

control period, of the State SO2 Group 

1 trading budget and the State’s threeyear variability limit under § 97.610(b); 

(C) Provided that the amount by 

which such total amount of SO2

emissions exceeds the State assurance 

level shall be the greater of the amounts 

of the exceedance calculated under 

paragraph (c)(2)(iii)(A) of this section 

and under paragraph (c)(2)(iii)(B) of this 

section. 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if the 

total amount of SO2 emissions from all 

TR SO2 Group 1 units in a State during 

a control period exceeds the State 

assurance level or if an owner’s share of 

total SO2 emissions from the TR SO2

Group 1 units in a State during a control 

period exceeds the owner’s assurance 

level. 

(v) To the extent an owner fails to 

hold TR SO2 Group 1 allowances for a 

control period in accordance with 

paragraphs (c)(2)(i) and (ii) of this 

section, 

(A) The owner shall pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed under the 

Clean Air Act; and 

(B) Each TR SO2 Group 1 allowance 

that the owner fails to hold for a control 

period in accordance with paragraphs 

(c)(2)(i) and (ii) of this section and each 

day of such control period shall 

constitute a separate violation of this 

subpart and the Clean Air Act. 

(3) Compliance periods. A TR SO2

Group 1 unit shall be subject to the 

requirements: 

(i) Under paragraph (c)(1) of this 

section for the control period starting on 

the later of January 1, 2012 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.630(b) and for each control period 

thereafter; and 

(ii) Under paragraph (c)(2) of this 

section for the control period starting on 

the later of January 1, 2014 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.630(b) and for each control period 

thereafter. 

(4) Vintage of deducted allowances. A 

TR SO2 Group 1 allowance shall not be 

deducted, for compliance with the 

requirements under paragraphs (c)(1) 

and (2) of this section, for a control 

period in a calendar year before the year 

for which the TR SO2 Group 1 

allowance was allocated. 

(5) Allowance Management System 

requirements. Each TR SO2 Group 1 

allowance shall be held in, deducted 

from, or transferred into, out of, or 

between Allowance Management 

System accounts in accordance with 

this subpart. 

(6) Limited authorization. (i) A TR 

SO2 Group 1 allowance is a limited 

authorization to emit one ton of SO2 in 

accordance with the TR SO2 Group 1 

Trading Program. 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit such authorization to 

the extent the Administrator determines 

is necessary or appropriate to 

implement any provision of the Clean 

Air Act. 

(7) Property right. A TR SO2 Group 1 

allowance does not constitute a property 

right. 

(d) Title V Permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of TR SO2 Group 1 

allowances in accordance with this 

subpart. 

(2) A description of whether a unit is 

required to monitor and report SO2

emissions using a continuous emission 

monitoring system (under §§ 75.10, 

75.11, and 75.16 of this chapter), an 

excepted monitoring system (under 

appendix D to part 75 of this chapter), 

a low mass emissions excepted 

monitoring methodology (under § 75.19 

of this chapter), or an alternative 

monitoring system (under subpart E of 

part 75 of this chapter) in accordance 

with §§ 97.630 through 97.635 may be 

added to, or changed in, a title V permit 

using minor permit modification 

procedures in accordance with 

§§ 70.7(e)(2) and 71.7(e)(1) of this 

chapter, provided that the requirements 

applicable to the described monitoring 

and reporting (as added or changed, 

respectively) are already incorporated in 

such permit. This paragraph explicitly 

provides that the addition of, or change 

to, a unit’s description as described in 

the prior sentence is eligible for minor 


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permit modification procedures in 

accordance with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. (1) Unless 

otherwise provided, the owners and 

operators of each TR SO2 Group 1 

source and each TR SO2 Group 1 unit 

at the source shall keep on site at the 

source each of the following documents 

(in hardcopy or electronic format) for a 

period of 5 years from the date the 

document is created. This period may 

be extended for cause, at any time 

before the end of 5 years, in writing by 

the Administrator. 

(i) The certificate of representation 

under § 97.616 for the designated 

representative for the source and each 

TR SO2 Group 1 unit at the source and 

all documents that demonstrate the 

truth of the statements in the certificate 

of representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such 

documents are superseded because of 

the submission of a new certificate of 

representation under § 97.616 changing 

the designated representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the TR SO2 Group 1 

Trading Program, including any 

monitoring plans and monitoring 

system certification and recertification 

applications. 

(2) The designated representative of a 

TR SO2 Group 1 source and each TR 

SO2 Group 1 unit at the source shall 

make all submissions required under 

the TR SO2 Group 1 Trading Program, 

including any submissions required for 

compliance with the TR SO2 Group 1 

assurance provisions. This requirement 

does not change, create an exemption 

from, or otherwise affect the responsible 

official submission requirements under 

a title V operating permit program in 

parts 70 and 71 of this chapter. 

(f) Liability. (1) Any provision of the 

TR SO2 Group 1 Trading Program that 

applies to a TR SO2 Group 1 source or 

the designated representative of a TR 

SO2 Group 1 source shall also apply to 

the owners and operators of such source 

and of the TR SO2 Group 1 units at the 

source. 

(2) Any provision of the TR SO2

Group 1 Trading Program that applies to 

a TR SO2 Group 1 unit or the designated 

representative of a TR SO2 Group 1 unit 

shall also apply to the owners and 

operators of such unit. 

(g) Effect on other authorities. No 

provision of the TR SO2 Group 1 

Trading Program or exemption under 

§ 97.605 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of a TR SO2 Group 1 

source or TR SO2 Group 1 unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.607 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 1 Trading Program, to begin on 

the occurrence of an act or event shall 

begin on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 1 Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

SO2 Group 1 Trading Program, falls on 

a weekend or a State or Federal holiday, 

the time period shall be extended to the 

next business day. 

§ 97.608 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR SO2 Group 1 Trading Program 

are set forth in part 78 of this chapter. 

§ 97.609 [Reserved] 

§ 97.610 State SO2 Group 1 trading 

budgets, new-unit set-asides, and variability 

limits. 

(a) The State SO2 Group 1 trading 

budgets and new-unit set-asides for 

allocations of TR SO2 Group 1 

allowances for the control periods in 

2012 and thereafter are as follows: 

State 

SO2 Group 1 trading budget 

(tons) * 

New-unit set-aside (tons) 

For 2012–2013 For 2014 and 

thereafter 

For 2012–2013 For 2014 and 

thereafter 

Georgia .................................................................................................... 233,260 85,717 6,998 2,572 

Illinois ....................................................................................................... 208,957 151,530 6,269 4,546 

Indiana ..................................................................................................... 400,378 201,412 12,011 6,042 

Iowa ......................................................................................................... 94,052 86,088 2,822 2,583 

Kentucky .................................................................................................. 219,549 113,844 6,586 3,415 

Michigan ................................................................................................... 251,337 155,675 7,540 4,670 

Missouri .................................................................................................... 203,689 158,764 6,111 4,763 

New York ................................................................................................. 66,542 42,041 1,996 1,261 

North Carolina .......................................................................................... 111,485 81,859 3,345 2,456 

Ohio ......................................................................................................... 464,964 178,307 13,949 5,349 

Pennsylvania ............................................................................................ 388,612 141,693 11,658 4,251 

Tennessee ............................................................................................... 100,007 100,007 3,000 3,000 

Virginia ..................................................................................................... 72,595 40,785 2,178 1,224 

West Virginia ............................................................................................ 205,422 119,016 6,163 3,570 

Wisconsin ................................................................................................. 96,439 66,683 2,893 2,000 

Total .................................................................................................. 3,117,288 1,723,421 93,519 51,703 

* Without variability limits. 

(b) The States’ one-year and three-year 

variability limits for the State SO2

Group 1 trading budgets for the control 

periods in 2014 and thereafter are as 

follows: 


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State 

One-year 

variability limits 

Three-year 

variability limits 

2014 and 

thereafter 

(tons) 

2016 and 

thereafter 

(tons) 

Georgia ................................................................................................................................................ 8,572 4,949 

Illinois ................................................................................................................................................... 15,153 8,749 

Indiana ................................................................................................................................................. 20,141 11,629 

Iowa ..................................................................................................................................................... 8,609 4,970 

Kentucky .............................................................................................................................................. 11,384 6,573 

Michigan ............................................................................................................................................... 15,568 8,988 

Missouri ................................................................................................................................................ 15,876 9,166 

New York ............................................................................................................................................. 4,204 2,427 

North Carolina ...................................................................................................................................... 8,186 4,726 

Ohio ..................................................................................................................................................... 17,831 10,295 

Pennsylvania ........................................................................................................................................ 14,169 8,181 

Tennessee ........................................................................................................................................... 10,001 5,774 

Virginia ................................................................................................................................................. 4,079 2,355 

West Virginia ........................................................................................................................................ 11,902 6,871 

Wisconsin ............................................................................................................................................. 6,668 3,850 

§ 97.611 Timing requirements for TR SO2

Group 1 allowance allocations. 

(a) Existing units. (1) TR SO2 Group 1 

allowances are allocated, for the control 

periods in 2012 and each year 

thereafter, as set forth in appendix A to 

this subpart. Listing a unit in such 

appendix does not constitute a 

determination that the unit is a TR SO2

Group 1 unit, and not listing a unit in 

such appendix does not constitute a 

determination that the unit is not a TR 

SO2 Group 1 unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit listed in 

appendix A to this subpart as being 

allocated TR SO2 Group 1 allowances 

does not operate, starting after 2011, 

during the control period in three 

consecutive years, such unit will not be 

allocated the TR SO2 Group 1 

allowances set forth in appendix A to 

this subpart for the unit for the control 

periods in the seventh year after the first 

such year and in each year after that 

seventh year. All TR SO2 Group 1 

allowances that would otherwise have 

been allocated to such unit will be 

allocated to the new unit set-aside for 

the respective years involved. If such 

unit resumes operation, the 

Administrator will allocate TR SO2

Group 1 allowances to the unit in 

accordance with paragraph (b) of this 

section. 

(b) New units. (1) By July 1, 2012 and 

July 1 of each year thereafter, the 

Administrator will calculate the TR SO2

Group 1 allowance allocation for each 

TR SO2 Group 1 unit, in accordance 

with § 97.612, for the control period in 

the year of the applicable calculation 

deadline under this paragraph and will 

promulgate a notice of availability of the 

results of the calculations. 

(2) For each notice of data availability 

required in paragraph (b)(1) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations are in 

accordance with § 97.612 and 

§§ 97.606(b)(2) and 97.630 through 

97.635. 

(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By September 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(c) Units that are not TR SO2 Group 

1 units. For each control period in 2012 

and thereafter, if the Administrator 

determines that TR SO2 Group 1 

allowances were allocated under 

paragraph (a) of this section for the 

control period to a recipient that is not 

actually a TR SO2 Group 1 unit under 

§ 97.604 as of January 1, 2012 or whose 

deadline for meeting monitor 

certification requirements under 

§ 97.630(b)(1) and (2) is after January 1, 

2012 or if the Administrator determines 

that TR SO2 Group 1 allowances were 

allocated under paragraph (b) of this 

section and § 97.612 for the control 

period to a recipient that is not actually 

a TR SO2 Group 1 unit under § 97.604 

as of January 1 of the control period, 

then the Administrator will notify the 

designated representative and will act in 

accordance with the following 

procedures: 

(1) Except as provided in paragraph 

(c)(2) or (3) of this section, the 

Administrator will not record such TR 

SO2 Group 1 allowances under § 97.621. 

(2) If the Administrator already 

recorded such TR SO2 Group 1 

allowances under § 97.621 and if the 

Administrator makes such 

determination before making deductions 

for the source that includes such 

recipient under § 97.624(b) for such 

control period, then the Administrator 

will deduct from the account in which 

such TR SO2 Group 1 allowances were 

recorded an amount of TR SO2 Group 1 

allowances allocated for the same or a 

prior control period equal to the amount 

of such already recorded TR SO2 Group 

1 allowances. The authorized account 

representative shall ensure that there are 

sufficient TR SO2 Group 1 allowances in 

such account for completion of the 

deduction. 

(3) If the Administrator already 

recorded such TR SO2 Group 1 

allowances under § 97.621 and if the 

Administrator makes such 

determination after making deductions 

for the source that includes such 

recipient under § 97.624(b) for such 

control period, then the Administrator 

will not make any deduction to take 

account of such already recorded TR 

SO2 Group 1 allowances. 

(4) The Administrator will transfer the 

TR SO2 Group 1 allowances that are not 

recorded, or that are deducted, in 

accordance with paragraphs (c)(1) and 

(2) of this section to the new unit setaside, for the State in which such 

recipient is located, for the control 

period in the year of such transfer if the 

notice required in paragraph (b)(1) of 

this section for the control period in that 

year has not been promulgated or, if 

such notice has been promulgated, in 

the next year. 


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§ 97.612 TR SO2 Group 1 allowance 

allocations for new units. 

(a) For each control period in 2012 

and thereafter, the Administrator will 

allocate, in accordance with the 

following procedures, TR SO2 Group 1 

allowances to TR SO2 Group 1 units in 

a State that are not listed in appendix 

A to this subpart, to TR SO2 Group 1 

units that are so listed and whose 

allocation of SO2 Group 1 allowances 

for such control period is covered by 

§ 97.611(c)(1) or (2), and to TR SO2

Group 1 units that are so listed and, 

pursuant to § 97.611(a)(2), are not 

allocated TR SO2 Group 1 allowances 

for such control period but that operate 

during the immediately preceding 

control period: 

(1) The Administrator will establish a 

separate new unit set-aside for each 

State for each control period in a given 

year. Each new unit set-aside will be 

allocated TR SO2 Group 1 allowances in 

an amount equal to the applicable 

amount of tons of SO2 emissions as set 

forth in § 97.610(a). Each new unit setaside will be allocated additional TR 

SO2 Group 1 allowances in accordance 

with § 97.611(a)(2) and (c)(4). 

(2) The designated representative of 

such TR SO2 Group 1 unit may submit 

to the Administrator a request, in a 

format prescribed by the Administrator, 

to be allocated TR SO2 Group 1 

allowances for a control period, starting 

with the later of the control period in 

2012, the first control period after the 

control period in which the TR SO2

Group 1 unit commences commercial 

operation (for a unit not listed in 

appendix A to this subpart), or the first 

control period after the control period in 

which the unit resumes operation (for a 

unit listed in appendix A of this 

subpart) and for each subsequent 

control period. 

(i) The request must be submitted on 

or before May 1 of the first control 

period for which TR SO2 Group 1 

allowances are sought and after the date 

on which the TR SO2 Group 1 unit 

commences commercial operation (for a 

unit not listed in appendix A of this 

subpart) or on which the unit resumes 

operation (for a unit listed in appendix 

A of this subpart). 

(ii) For each control period for which 

an allocation is sought, the request must 

be for TR SO2 Group 1 allowances in an 

amount equal to the unit’s total tons of 

SO2 emissions during the immediately 

preceding control period. 

(3) The Administrator will review 

each TR SO2 Group 1 allowance 

allocation request under paragraph 

(a)(2) of this section and will accept the 

request only if it meets the requirements 

of paragraph (a)(2) of this section. The 

Administrator will allocate TR SO2

Group 1 allowances for each control 

period pursuant to an accepted request 

as follows: 

(i) After May 1 of such control period, 

the Administrator will determine the 

sum of the TR SO2 Group 1 allowances 

requested in all accepted allowance 

allocation requests for such control 

period. 

(ii) If the amount of TR SO2 Group 1 

allowances in the new unit set-aside for 

such control period is greater than or 

equal to the sum under paragraph 

(a)(3)(i) of this section, then the 

Administrator will allocate the amount 

of TR SO2 Group 1 allowances requested 

to each TR SO2 Group 1 unit covered by 

an accepted allowance allocation 

request. 

(iii) If the amount of TR SO2 Group 1 

allowances in the new unit set-aside for 

such control period is less than the sum 

under paragraph (a)(3)(i) of this section, 

then the Administrator will allocate to 

each TR SO2 Group 1 unit covered by 

an accepted allowance allocation 

request the amount of the TR SO2 Group 

1 allowances requested, multiplied by 

the amount of TR SO2 Group 1 

allowances in the new unit set-aside for 

such control period, divided by the sum 

determined under paragraph (a)(3)(i) of 

this section, and rounded to the nearest 

allowance. 

(iv) The Administrator will notify, 

through the promulgation of the notices 

of data availability described in 

§ 97.611(b), each designated 

representative that submitted an 

allowance allocation request of the 

amount of TR SO2 Group 1 allowances 

(if any) allocated for such control period 

to the TR SO2 Group 1 unit covered by 

the request. 

(b) If, after completion of the 

procedures under paragraph (a)(4) of 

this section for a control period, any 

unallocated TR SO2 Group 1 allowances 

remain in the new unit set-aside under 

paragraph (a) of this section for a State 

for such control period, the 

Administrator will allocate to each TR 

SO2 Group 1 unit that is in the State, is 

listed in appendix A to this subpart, and 

continues to be allocated TR SO2 Group 

1 allowances for such control period in 

accordance with § 97.611(a)(2), an 

amount of TR SO2 Group 1 allowances 

equal to the following: The total amount 

of such remaining unallocated TR SO2

Group 1 allowances in such new unit 

set-aside, multiplied by the unit’s 

allocation under § 97.611(a) for such 

control period, divided by the 

remainder of the amount of tons in the 

applicable State SO2 Group 1 trading 

budget minus the amount of tons in 

such new unit set-aside, and rounded to 

the nearest allowance. 

§ 97.613 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.615, 

each TR SO2 Group 1 source, including 

all TR SO2 Group 1 units at the source, 

shall have one and only one designated 

representative, with regard to all matters 

under the TR SO2 Group 1 Trading 

Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR SO2 Group 1 units 

at the source and shall act in accordance 

with the certification statement in 

§ 97.616(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.616: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR SO2 Group 1 unit at the 

source in all matters pertaining to the 

TR SO2 Group 1 Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

source and each TR SO2 Group 1 unit 

at the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.615, 

each TR SO2 Group 1 source may have 

one and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR SO2

Group 1 units at the source and shall act 

in accordance with the certification 

statement in § 97.616(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.616, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 


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45428 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each TR SO2 Group 1 unit 

at the source shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding the source or 

any such unit. (c) Except in this section, 

§ 97.602, and §§ 97.614 through 97.618, 

whenever the term ‘‘designated 

representative’’ is used in this subpart, 

the term shall be construed to include 

the designated representative or any 

alternate designated representative. 

§ 97.614 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.618 

concerning delegation of authority to 

make submissions, each submission 

under the TR SO2 Group 1 Trading 

Program shall be made, signed, and 

certified by the designated 

representative or alternate designated 

representative for each TR SO2 Group 1 

source and TR SO2 Group 1 unit for 

which the submission is made. Each 

such submission shall include the 

following certification statement by the 

designated representative or alternate 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR SO2

Group 1 source or a TR SO2 Group 1 

unit only if the submission has been 

made, signed, and certified in 

accordance with paragraph (a) of this 

section and § 97.618. 

§ 97.615 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators. 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.616. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the TR SO2 Group 1 source 

and the TR SO2 Group 1 units at the 

source. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.616. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the TR SO2

Group 1 source and the TR SO2 Group 

1 units at the source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a TR SO2 Group 1 source or a TR SO2

Group 1 unit is not included in the list 

of owners and operators in the 

certificate of representation under 

§ 97.616, such owner or operator shall 

be deemed to be subject to and bound 

by the certificate of representation, the 

representations, actions, inactions, and 

submissions of the designated 

representative and any alternate 

designated representative of the source 

or unit, and the decisions and orders of 

the Administrator, as if the owner or 

operator were included in such list. 

(2) Within 30 days after any change in 

the owners and operators of a TR SO2

Group 1 source or a TR SO2 Group 1 

unit, including the addition of a new 

owner or operator, the designated 

representative or any alternate 

designated representative shall submit a 

revision to the certificate of 

representation under § 97.616 amending 

the list of owners and operators to 

include the change. 

§ 97.616 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR SO2 Group 

1 source, and each TR SO2 Group 1 unit 

at the source, for which the certificate 

of representation is submitted, 

including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, unit identification number 

and type, identification number and 

nameplate capacity (in MWe rounded to 

the nearest tenth) of each generator 

served by each such unit, and actual or 

projected date of commencement of 

commercial operation. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR SO2 Group 1 source and of 

each TR SO2 Group 1 unit at the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

SO2 Group 1 unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

SO2 Group 1 Trading Program on behalf 

of the owners and operators of the 

source and of each TR SO2 Group 1 unit 

at the source and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order issued to 

me by the Administrator regarding the 

source or unit.’’ 

(iii) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a TR SO2 Group 1 

unit, or where a utility or industrial 

customer purchases power from a TR 

SO2 Group 1 unit under a life-of-theunit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘designated representative’ or ‘alternate 

designated representative’, as 

applicable, and of the agreement by 

which I was selected to each owner and 

operator of the source and of each TR 

SO2 Group 1 unit at the source; and TR 

SO2 Group 1 allowances and proceeds 

of transactions involving TR SO2 Group 

1 allowances will be deemed to be held 

or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of TR SO2 Group 1 

allowances by contract, TR SO2 Group 

1 allowances and proceeds of 

transactions involving TR SO2 Group 1 

allowances will be deemed to be held or 


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distributed in accordance with the 

contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 97.617 Objections concerning 

designated representative and alternate 

designated representative. 

(a) Once a complete certificate of 

representation under § 97.616 has been 

submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 97.616 is 

received by the Administrator. 

(b) Except as provided in § 97.615(a) 

or (b), no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the TR SO2 Group 1 Trading 

Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of TR 

SO2 Group 1 allowance transfers. 

§ 97.618 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (a) or (b) of this section, the 

designated representative or alternate 

designated representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to as an 

‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.618(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.618(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.618 is terminated.’’. 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.619 [Reserved] 

§ 97.620 Establishment of Allowance 

Management System accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.616, the 

Administrator will establish a 

compliance account for the TR SO2

Group 1 source for which the certificate 

of representation was submitted, unless 

the source already has a compliance 

account. The designated representative 

and any alternate designated 

representative of the source shall be the 

authorized account representative and 

the alternate authorized account 

representative respectively of the 

compliance account. 

(b) General accounts—(1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring TR 

SO2 Group 1 allowances, by submitting 

to the Administrator a complete 

application for a general account. Such 

application shall designate one and only 

one authorized account representative 

and may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR SO2 Group 1 allowances 

held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 


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represent their ownership interest with 

respect to the TR SO2 Group 1 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR SO2 Group 1 allowances 

held in the general account. I certify that 

I have all the necessary authority to 

carry out my duties and responsibilities 

under the TR SO2 Group 1 Trading 

Program on behalf of such persons and 

that each such person shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

order or decision issued to me by the 

Administrator regarding the general 

account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to TR 

SO2 Group 1 allowances held in the 

general account in all matters pertaining 

to the TR SO2 Group 1 Trading Program, 

notwithstanding any agreement between 

the authorized account representative 

and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to TR 

SO2 Group 1 allowances held in the 

general account shall be bound by any 

order or decision issued to the 

authorized account representative or 

alternate authorized account 

representative by the Administrator 

regarding the general account. (ii) 

Except as provided in paragraph (b)(5) 

of this section concerning delegation of 

authority to make submissions, each 

submission concerning the general 

account shall be made, signed, and 

certified by the authorized account 

representative or any alternate 

authorized account representative for 

the persons having an ownership 

interest with respect to TR SO2 Group 

1 allowances held in the general 

account. Each such submission shall 

include the following certification 

statement by the authorized account 

representative or any alternate 

authorized account representative: ‘‘I am 

authorized to make this submission on 

behalf of the persons having an 

ownership interest with respect to the 

TR SO2 Group 1 allowances held in the 

general account. I certify under penalty 

of law that I have personally examined, 

and am familiar with, the statements 

and information submitted in this 

document and all its attachments. Based 

on my inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(b)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR SO2 Group 1 

allowances in the general account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR SO2 Group 1 allowances in the 

general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR SO2 Group 1 allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such person shall 

be deemed to be subject to and bound 

by the application for a general account, 

the representation, actions, inactions, 

and submissions of the authorized 

account representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to SO2 Group 1 

allowances in the general account, 

including the addition of a new person, 

the authorized account representative or 

any alternate authorized account 

representative shall submit a revision to 

the application for a general account 

amending the list of persons having an 

ownership interest with respect to the 

TR SO2 Group 1 allowances in the 

general account to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. (i) 

Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 


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representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account shall affect any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative or the 

finality of any decision or order by the 

Administrator under the TR SO2 Group 

1 Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

SO2 Group 1 allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (b)(5)(i) or (ii) of this section, 

the authorized account representative or 

alternate authorized account 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(B) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such natural person (referred to 

as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (b)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 

97.620(b)(5)(iv) shall be deemed to be an 

electronic submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 40 

CFR 97.620(b)(5)(iv), I agree to maintain 

an e-mail account and to notify the 

Administrator immediately of any 

change in my e-mail address unless all 

delegation of authority by me under 40 

CFR 97.620(b)(5) is terminated.’’. 

(iv) A notice of delegation submitted 

under paragraph (b)(5)(iii) of this 

section shall be effective, with regard to 

the authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

(v) Any electronic submission covered 

by the certification in paragraph 

(b)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (b)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

(6)(i) The authorized account 

representative or alternate authorized 

account representative of a general 

account may submit to the 

Administrator a request to close the 

account. Such request shall include a 

correctly submitted TR SO2 Group 1 

allowance transfer under § 97.622 for 

any TR SO2 Group 1 allowances in the 

account to one or more other Allowance 

Management System accounts. 

(ii) If a general account has no TR SO2

Group 1 allowance transfers to or from 

the account for a 12-month period or 

longer and does not contain any TR SO2

Group 1 allowances, the Administrator 

may notify the authorized account 

representative for the account that the 

account will be closed after 20 business 

days after the notice is sent. The 

account will be closed after the 20-day 

period unless, before the end of the 20- 

day period, the Administrator receives a 

correctly submitted TR SO2 Group 1 

allowance transfer under § 97.622 to the 

account or a statement submitted by the 

authorized account representative or 

alternate authorized account 

representative demonstrating to the 

satisfaction of the Administrator good 

cause as to why the account should not 

be closed. 

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section. 

(d) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of an Allowance 

Management System account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of TR SO2 Group 1 

allowances in the account, only if the 

submission has been made, signed, and 

certified in accordance with §§ 97.614(a) 

and 97.618 or paragraphs (b)(2)(ii) and 

(b)(5) of this section. 

§ 97.621 Recordation of TR SO2 Group 1 

allowance allocations. 

(a) By September 1, 2011, the 

Administrator will record in each TR 

SO2 Group 1 source’s compliance 

account the TR SO2 Group 1 allowances 

allocated for the TR SO2 Group 1 units 

at the source in accordance with 

§§ 97.611(a) for the control periods in 

2012, 2013, and 2014. 

(b) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

record in each TR SO2 Group 1 source’s 

compliance account the TR SO2 Group 

1 allowances allocated for the TR SO2

Group 1 units at the source in 

accordance with § 97.611(a) for the 

control period in the third year after the 

year of the applicable recordation 

deadline under this paragraph. 

(c) By September 1, 2012 and 

September 1 of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 1 source’s compliance 

account the TR SO2 Group 1 allowances 

allocated for the TR SO2 Group 1 units 

at the source in accordance with 

§ 97.612 for the control period in the 

year of the applicable recordation 

deadline under this paragraph. 

(d) When recording the allocation of 

TR SO2 Group 1 allowances for a TR 


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45432 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

SO2 Group 1 unit in a compliance 

account, the Administrator will assign 

each TR SO2 Group 1 allowance a 

unique identification number that will 

include digits identifying the year of the 

control period for which the TR SO2

Group 1 allowance is allocated. 

§ 97.622 Submission of TR SO2 Group 1 

allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR SO2 Group 1 allowance transfer shall 

submit the transfer to the Administrator. 

(b) A TR SO2 Group 1 allowance 

transfer shall be correctly submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR SO2

Group 1 allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR SO2 Group 1 

allowance identified by serial number in 

the transfer. 

§ 97.623 Recordation of TR SO2 Group 1 

allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR SO2 Group 1 

allowance transfer, the Administrator 

will record a TR SO2 Group 1 allowance 

transfer by moving each TR SO2 Group 

1 allowance from the transferor account 

to the transferee account as specified by 

the request, provided that the transfer is 

correctly submitted under § 97.622. 

(b)(1) A TR SO2 Group 1 allowance 

transfer that is submitted for recordation 

after the allowance transfer deadline for 

a control period and that includes any 

TR SO2 Group 1 allowances allocated 

for any control period before such 

allowance transfer deadline will not be 

recorded until after the Administrator 

completes the deductions under 

§ 97.624 for the control period 

immediately before such allowance 

transfer deadline. 

(2) A TR SO2 Group 1 allowance 

transfer that is submitted for recordation 

after the deadline for holding TR SO2

Group 1 allowances described in 

§ 97.625(b)(5) and that includes any TR 

SO2 Group 1 allowances allocated for a 

control period before the year of such 

deadline will not be recorded until after 

the Administrator completes the 

deductions under § 97.625 for the 

control period immediately before the 

year of such deadline. 

(c) Where a TR SO2 Group 1 

allowance transfer is not correctly 

submitted under § 97.622, the 

Administrator will not record such 

transfer. 

(d) Within 5 business days of 

recordation of a TR SO2 Group 1 

allowance transfer under paragraphs (a) 

and (b) of the section, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR SO2 Group 1 allowance transfer 

that is not correctly submitted under 

§ 97.622, the Administrator will notify 

the authorized account representatives 

of both accounts subject to the transfer 

of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.624 Compliance with TR SO2 Group 1 

emissions limitation. 

(a) Availability for deduction for 

compliance. TR SO2 Group 1 allowances 

are available to be deducted for 

compliance with a source’s TR SO2

Group 1 emissions limitation for a 

control period in a given year only if the 

TR SO2 Group 1 allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in the source’s 

compliance account as of the allowance 

transfer deadline for such control 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 97.623, of TR SO2 Group 1 allowance 

transfers submitted by the allowance 

transfer deadline for a control period, 

the Administrator will deduct from the 

compliance account TR SO2 Group 1 

allowances available under paragraph 

(a) of this section in order to determine 

whether the source meets the TR SO2

Group 1 emissions limitation for such 

control period, as follows: 

(1) Until the amount of TR SO2 Group 

1 allowances deducted equals the 

number of tons of total SO2 emissions 

from all TR SO2 Group 1 units at the 

source for such control period; or 

(2) If there are insufficient TR SO2

Group 1 allowances to complete the 

deductions in paragraph (b)(1) of this 

section, until no more TR SO2 Group 1 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(c)(1) Identification of TR SO2 Group 

1 allowances by serial number. The 

authorized account representative for a 

source’s compliance account may 

request that specific TR SO2 Group 1 

allowances, identified by serial number, 

in the compliance account be deducted 

for emissions or excess emissions for a 

control period in accordance with 

paragraph (b) or (d) of this section. In 

order to be complete, such request shall 

be submitted to the Administrator by 

the allowance transfer deadline for such 

control period and include, in a format 

prescribed by the Administrator, the 

identification of the TR SO2 Group 1 

source and the appropriate serial 

numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR SO2

Group 1 allowances under paragraph (b) 

or (d) of this section from the source’s 

compliance account in accordance with 

a complete request under paragraph 

(c)(1) of this section or, in the absence 

of such request or in the case of 

identification of an insufficient amount 

of TR SO2 Group 1 allowances in such 

request, on a first-in, first-out (FIFO) 

accounting basis in the following order: 

(i) Any TR SO2 Group 1 allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR SO2 Group 1 allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a year in 

which the TR SO2 Group 1 source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account an amount of TR SO2 Group 1 

allowances, allocated for the control 

period in the immediately following 

year, equal to two times the number of 

tons of the source’s excess emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.625 Compliance with TR SO2 Group 1 

assurance provisions. 

(a) Availability for deduction. TR SO2

Group 1 allowances are available to be 

deducted for compliance with the TR 

SO2 Group 1 assurance provisions for a 

control period in a given year by an 

owner of one or more TR SO2 Group 1 

units in a State only if the TR SO2

Group 1 allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in a compliance account, 

designated by the owner in accordance 


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with paragraph (b)(4)(ii) of this section, 

of one of the owner’s TR SO2 Group 1 

sources in the State as of the deadline 

established in paragraph (b)(5) of this 

section. 

(b) Deductions for compliance. The 

Administrator will deduct TR SO2

Group 1 allowances available under 

paragraph (a) of this section for 

compliance with the TR SO2 Group 1 

assurance provisions for a State for a 

control period in a given year in 

accordance with the following 

procedures: 

(1) By June 1, 2015 and June 1 of each 

year thereafter, the Administrator will: 

(i) Calculate, separately for each State, 

the total amount of SO2 emissions from 

all TR SO2 Group 1 units in the State 

during the control period in the year 

before the year of this calculation 

deadline and the amount, if any, by 

which such total amount of NOX

emissions exceeds the State assurance 

level as described in § 97.606(c)(2)(iii); 

and 

(ii) Promulgate a notice of availability 

of the results of the calculations 

required in paragraph (b)(1)(i) of this 

section, including separate calculations 

of the SO2 emissions for each TR SO2

Group 1 unit and of the amounts 

described in §§ 97.606(c)(2)(iii)(A) and 

(B) for each State. 

(2) The Administrator will provide an 

opportunity for submission of objections 

to the calculations referenced by each 

notice described in paragraph (b)(1) of 

this section. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each TR 

SO2 Group 1 unit and each State for the 

control period in the year involved are 

in accordance with § 97.606(c)(2)(iii) 

and §§ 97.606(b) and 97.630 through 

97.635. 

(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By August 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(3) For each notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and for any State identified in 

such notice as having TR SO2 Group 1 

sources with total SO2 emissions 

exceeding the State assurance level for 

a control period, as described in 

§ 97.606(c)(2)(iii): 

(i) By August 15 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

SO2 Group 1 source in each such State 

shall submit a statement, in a format 

prescribed by the Administrator: 

(A) Listing all the owners of each TR 

SO2 Group 1 unit at the source, 

explaining how the selection of each 

owner for inclusion on the list is 

consistent with the definition of 

‘‘owner’’ in § 97.602, and listing, 

separately for each unit, the percentage 

of the legal, equitable, leasehold, or 

contractual reservation or entitlement 

for each such owner as of midnight of 

December 31 of the control period in the 

year involved; and 

(B) For each TR SO2 Group 1 unit at 

the source that operates during, but is 

allocated no TR SO2 Group 1 allowances 

for, the control period in the year 

involved, identifying whether the unit is 

a coal-fired boiler, simple combustion 

turbine, or combined cycle turbine cycle 

and providing the unit’s allowable SO2

emission rate for such control period. 

(ii) By September 15 immediately 

after the promulgation of such notice, 

the Administrator will calculate, for 

each such State and each owner of one 

or more TR SO2 Group 1 units in the 

State and for the control period in the 

year involved, each owner’s share of the 

total SO2 emissions from all TR SO2

Group 1 units in the State, each owner’s 

assurance level, and the amount (if any) 

of TR SO2 Group 1 allowances that each 

owner must hold in accordance with the 

calculation formula in § 97.606(c)(2)(i) 

and will promulgate a notice of 

availability of the results of these 

calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 

required in paragraph (b)(3)(ii) of this 

section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each owner 

for the control period in the year 

involved are consistent with the SO2

emissions for the relevant TR SO2 Group 

1 units as set forth in the notice required 

in paragraph (b)(2)(ii) of this section, the 

definitions of ‘‘owner’’, ‘‘owner’s 

assurance level’’, and ‘‘owner’s share’’ in 

§ 97.602, and the calculation formula in 

§ 97.606(c)(2)(i) and shall not raise any 

issues about any data used in the notice 

of data availability required in 

paragraph (b)(2)(ii) of this section. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are consistent with the 

data and provisions referenced in 

paragraph (b)(3)(iii)(A) of this section. 

By November 15 immediately after the 

promulgation of such notice, the 

Administrator will promulgate a notice 

of availability of any adjustments that 

the Administrator determines to be 

necessary and the reasons for accepting 

or rejecting any objections submitted in 

accordance with paragraph (b)(3)(iii)(A) 

of this section. 

(4) By December 1 immediately after 

the promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section: 

(i) Each owner identified, in such 

notice, as owning one or more TR SO2

Group 1 units in a State and as being 

required to hold TR SO2 Group 1 

allowances shall designate the 

compliance account of one of the 

sources at which such unit or units are 

located to hold such required TR SO2

Group 1 allowances; 

(ii) The authorized account 

representative for the compliance 

account designated under paragraph 

(b)(4)(i) of this section shall submit to 

the Administrator a statement, in a 

format prescribed by the Administrator, 

making this designation. 

(5)(i) As of midnight of December 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(3)(iii)(B) of this section, 

each owner described in paragraph 

(b)(4)(i) of this section shall hold in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section the total amount 

of TR SO2 Group 1 allowances, available 

for deduction under paragraph (a) of 

this section, equal to the amount the 

owner is required to hold as calculated 

by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(5)(i) of this section, if December 15 

is not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(6) After December 15 (or the date 

described in paragraph (b)(5)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.623, of TR SO2 Group 1 allowance 

transfers submitted by midnight of such 

date, the Administrator will deduct 

from each compliance account 

designated in accordance with 

paragraph (b)(4)(ii) of this section, TR 

SO2 Group 1 allowances available under 

paragraph (a) of this section, as follows: 

(i) Until the amount of TR SO2 Group 

1 allowances deducted equals the 


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amount that the owner designating the 

compliance account is required to hold 

as calculated by the Administrator and 

referenced in the notice required in 

paragraph (b)(3)(iii)(B) of this section; or 

(ii) If there are insufficient TR SO2

Group 1 allowances to complete the 

deductions in paragraph (b)(6)(i) of this 

section, until no more TR SO2 Group 1 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(7) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notices of data availability required 

in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) 

of this section respectively for a control 

period, of any data used in making the 

calculations referenced in such notice, 

the amount of TR SO2 Group 1 

allowances that each owner is required 

to hold in accordance with 

§ 97.606(c)(2)(i) for the control period in 

the year involved shall continue to be 

such amount as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(3)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR SO2 Group 1 allowances that 

owners are required to hold in 

accordance with the calculation formula 

in § 97.606(c)(2)(i) for the control period 

in the year involved with regard to the 

State involved, provided that— 

(A) With regard to such litigation 

involving such notice required in 

paragraph (b)(2)(ii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(ii) of this section; and 

(B) With regard to such litigation 

involving such notice required in 

paragraph (b)(3)(iii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(3)(iii) of this section. 

(ii) If any such data are revised by the 

owners and operators of a source whose 

designated representative submitted 

such data under paragraph (b)(3)(i) of 

this section, as a result of a decision in 

or settlement of litigation concerning 

such submission, then the 

Administrator will use the data as so 

revised to recalculate the amounts of TR 

SO2 Group 1 allowances that owners are 

required to hold in accordance with the 

calculation formula in § 97.606(c)(2)(i) 

for the control period in the year 

involved with regard to the State 

involved, provided that such litigation 

was initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(3)(iii)(B) of this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(7)(i) and (b)(7)(ii) of this 

section, the amount of TR SO2 Group 1 

allowances that an owner is required to 

hold for the control period in the year 

involved with regard to the State 

involved— 

(A) Where the amount of TR SO2

Group 1 allowances that an owner is 

required to hold increases as a result of 

the use of all such revised data, the 

Administrator will establish a new, 

reasonable deadline on which the owner 

shall hold the additional amount of TR 

SO2 Group 1 allowances in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section. The owner’s 

failure to hold such additional amount, 

as required, before the new deadline 

shall not be a violation of the Clean Air 

Act. The owner’s failure to hold such 

additional amount, as required, as of the 

new deadline shall be a violation of the 

Clean Air Act. Each TR SO2 Group 1 

allowance that the owner fails to hold 

as required as of the new deadline, and 

each day in the control period in the 

year involved, shall be a separate 

violation of the Clean Air Act. After 

such deadline, the Administrator will 

make the appropriate deductions from 

the compliance account. 

(B) For an owner for which the 

amount of TR SO2 Group 1 allowances 

required to be held decreases as a result 

of the use of all such revised data, the 

Administrator will record, in the 

compliance account that the owner 

designated in accordance with 

paragraph (b)(4)(ii) of this section, an 

amount of TR SO2 Group 1 allowances 

equal to the amount of the decrease to 

the extent such amount was previously 

deducted from the compliance account 

under paragraph (b)(6) of this section 

(and has not already been restored to the 

compliance account) for the control 

period in the year involved. 

(C) Each TR SO2 Group 1 allowance 

held and deducted under paragraph 

(b)(7)(iii)(A) of this section, or recorded 

under paragraph (b)(7)(iii)(B) of this 

section, as a result of recalculation of 

requirements under the TR SO2 Group 

1 assurance provisions for a control 

period in a given year must be a TR SO2

Group 1 allowance allocated for a 

control period in the same or a prior 

year. 

(c)(1) Identification of TR SO2 Group 

1 allowances by serial number. The 

authorized account representative for 

each source’s compliance account 

designated in accordance with 

paragraph (b)(4)(ii) of this section may 

request that specific TR SO2 Group 1 

allowances, identified by serial number, 

in the compliance account be deducted 

in accordance with paragraph (b)(6) or 

(7) of this section. In order to be 

complete, such request shall be 

submitted to the Administrator by the 

allowance-holding deadline described 

in paragraph (b)(5) of this section and 

include, in a format prescribed by the 

Administrator, the identification of the 

compliance account and the appropriate 

serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR SO2

Group 1 allowances under paragraphs 

(b)(6) and (7) of this section from each 

source’s compliance account designated 

under paragraph (b)(4)(ii) of this section 

in accordance with a complete request 

under paragraph (c)(1) of this section or, 

in the absence of such request or in the 

case of identification of an insufficient 

amount of TR SO2 Group 1 allowances 

in such request, on a first-in, first-out 

(FIFO) accounting basis in the following 

order: 

(i) Any TR SO2 Group 1 allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR SO2 Group 1 allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) of this section. 

§ 97.626 Banking. 

(a) A TR SO2 Group 1 allowance may 

be banked for future use or transfer in 

a compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any TR SO2 Group 1 allowance 

that is held in a compliance account or 

a general account will remain in such 


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account unless and until the TR SO2

Group 1 allowance is deducted or 

transferred under § 97.611(c), § 97.623, 

§ 97.624, § 97.625, 97.627, 97.628, 

97.642, or 97.643. 

§ 97.627 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.628 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR SO2

Group 1 Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

SO2 Group 1 allowances from or transfer 

TR SO2 Group 1 allowances to a 

source’s compliance account based on 

the information in a submission, as 

adjusted under paragraph (a)(1) of this 

section, and record such deductions and 

transfers. 

§ 97.629 [Reserved] 

§ 97.630 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR SO2 Group 1 

unit, shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and subparts F and G of part 75 of this 

chapter. For purposes of applying such 

requirements, the definitions in § 97.602 

and in § 72.2 of this chapter shall apply, 

the terms ‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘TR SO2

Group 1 unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively as defined in 

§ 97.602, and the term ‘‘newly affected 

unit’’ shall be deemed to mean ‘‘newly 

affected TR SO2 Group 1 unit.’’ The 

owner or operator of a unit that is not 

a TR SO2 Group 1 unit but that is 

monitored under § 75.16(b)(2) of this 

chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a TR SO2

Group 1 unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR SO2 Group 

1 unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring SO2 mass emissions and 

individual unit heat input (including all 

systems required to monitor SO2

concentration, stack gas moisture 

content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as 

applicable, in accordance with §§ 75.11 

and 75.16 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.631 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates. The owner or 

operator shall record, report, and 

quality-assure the data from the 

monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

SO2 Group 1 unit that commences 

commercial operation before July 1, 

2011, by January 1, 2012. 

(2) For the owner or operator of a TR 

SO2 Group 1 unit that commences 

commercial operation on or after July 1, 

2011, by the later of the following dates: 

(i) January 1, 2012; or 

(ii) 180 calendar days, whichever 

occurs first, after the date on which the 

unit commences commercial operation. 

(3) For the owner or operator of a TR 

SO2 Group 1 unit for which 

construction of a new stack or flue or 

installation of add-on SO2 emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1) or (2) of this section, by 90 unit 

operating days or 180 calendar days, 

whichever occurs first, after the date on 

which emissions first exit to the 

atmosphere through the new stack or 

flue or add-on SO2 emissions controls. 

(4) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a unit for 

which a TR opt-in application is 

submitted and not withdrawn and is not 

yet approved or disapproved, by the 

date specified in § 97.641(c). 

(5) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a TR SO2

Group 1 opt-in unit, by the date on 

which the TR SO2 Group 1 opt-in unit 

enters the TR SO2 Group 1 Trading 

Program as provided in § 97.641(h). 

(c) Reporting data. The owner or 

operator of a TR SO2 Group 1 unit that 

does not meet the applicable 

compliance date set forth in paragraph 

(b) of this section for any monitoring 

system under paragraph (a)(1) of this 

section shall, for each such monitoring 

system, determine, record, and report 

maximum potential (or, as appropriate, 

minimum potential) values for SO2

concentration, stack gas flow rate, stack 

gas moisture content, fuel flow rate, and 

any other parameters required to 

determine SO2 mass emissions and heat 

input in accordance with § 75.31(b)(2) 

or (c)(3) of this chapter or section 2.4 of 

appendix D to part 75 of this chapter, as 

applicable. 

(d) Prohibitions. (1) No owner or 

operator of a TR SO2 Group 1 unit shall 

use any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this subpart without having obtained 

prior written approval in accordance 

with § 97.635. 

(2) No owner or operator of a TR SO2

Group 1 unit shall operate the unit so 

as to discharge, or allow to be 

discharged, SO2 emissions to the 

atmosphere without accounting for all 

such emissions in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter. 

(3) No owner or operator of a TR SO2

Group 1 unit shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording SO2 mass emissions 

discharged into the atmosphere or heat 

input, except for periods of 

recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the applicable provisions of this 

subpart and part 75 of this chapter. 

(4) No owner or operator of a TR SO2

Group 1 unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.605 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 


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pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.631(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR SO2 Group 1 unit is 

subject to the applicable provisions of 

§ 75.4(d) of this chapter concerning 

units in long-term cold storage. 

§ 97.631 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR SO2

Group 1 unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 97.630(a)(1) if the following conditions 

are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B and D to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.630(a)(1) exempt 

from initial certification requirements 

under paragraph (a) of this section. 

(c) [Reserved] 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR SO2 Group 1 unit shall comply 

with the following initial certification 

and recertification procedures, for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendix D to part 75 of this 

chapter) under § 97.630(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.630(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.630(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.630(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record SO2 mass emissions or heat input 

rate or to meet the quality-assurance and 

quality-control requirements of § 75.21 

of this chapter or appendix B to part 75 

of this chapter, the owner or operator 

shall recertify the monitoring system in 

accordance with § 75.20(b) of this 

chapter. Furthermore, whenever the 

owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit’s operation 

that may significantly change the stack 

flow or concentration profile, the owner 

or operator shall recertify each 

continuous emission monitoring system 

whose accuracy is potentially affected 

by the change, in accordance with 

§ 75.20(b) of this chapter. Examples of 

changes to a continuous emission 

monitoring system that require 

recertification include: Replacement of 

the analyzer, complete replacement of 

an existing continuous emission 

monitoring system, or change in 

location or orientation of the sampling 

probe or site. Any fuel flowmeter system 

under § 97.630(a)(1) is subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.630(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 

procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word ‘‘certified’’ 

is replaced by with the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.633. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR SO2 Group 1 Trading Program for 

a period not to exceed 120 days after 

receipt by the Administrator of the 

complete certification application for 

the monitoring system under paragraph 

(d)(3)(ii) of this section. Data measured 

and recorded by the provisionally 

certified monitoring system, in 

accordance with the requirements of 

part 75 of this chapter, will be 

considered valid quality-assured data 

(retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR SO2 Group 1 Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. The 120-day 


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review period specified in paragraph 

(d)(3) of this section shall not begin 

before receipt of a complete certification 

application. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.632(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved SO2 pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

SO2 and the maximum potential flow 

rate, as defined in sections 2.1.1.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(2) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(3) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.632 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or appendix D to part 75 of 

this chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.631 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

Administrator or any permitting 

authority. By issuing the notice of 

disapproval, the Administrator revokes 

prospectively the certification status of 

the monitoring system. The data 

measured and recorded by the 

monitoring system shall not be 

considered valid quality-assured data 

from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 97.631 for each 

disapproved monitoring system. 

§ 97.633 Notifications concerning 

monitoring. 

The designated representative of a TR 

SO2 Group 1 unit shall submit written 

notice to the Administrator in 

accordance with § 75.61 of this chapter. 

§ 97.634 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in this section, the 

applicable recordkeeping and reporting 

requirements in subparts F and G of part 

75 of this chapter, and the requirements 

of § 97.614(a). 

(b) Monitoring plans. The owner or 

operator of a TR SO2 Group 1 unit shall 

comply with requirements of § 75.62 of 

this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.631, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) The designated representative 

shall report the SO2 mass emissions data 

and heat input data for the TR SO2

Group 1 unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering 

January 1, 2012 through March 31, 2012; 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.630(b), unless 

that quarter is the third or fourth quarter 

of 2011, in which case reporting shall 


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commence in the quarter covering 

January 1, 2012 through March 31, 2012; 

(iii) Notwithstanding paragraphs 

(d)(1)(i) and (ii) of this section, for a unit 

for which a TR opt-in application is 

submitted and not withdrawn and is not 

yet approved or disapproved, the 

calendar quarter corresponding to the 

date specified in § 97.641(c); and 

(iv) Notwithstanding paragraphs 

(d)(1)(i) and (ii) of this section, for a TR 

SO2 Group 1 opt-in unit, the calendar 

quarter corresponding to the date on 

which the TR SO2 Group 1 opt-in unit 

enters the TR SO2 Group 1 Trading 

Program as provided in § 97.641(h). 

(2) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.64 of this chapter. 

(3) For TR SO2 Group 1 units that are 

also subject to the Acid Rain Program, 

TR NOX Annual Trading Program, or TR 

NOX Ozone Season Trading Program, 

quarterly reports shall include the 

applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the SO2 mass emission data, 

heat input data, and other information 

required by this subpart. 

(4) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(ii) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(2) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on SO2

emission controls and for all hours 

where SO2 data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate SO2

emissions. 

§ 97.635 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR SO2 Group 1 unit may submit a 

petition under § 75.66 of this chapter to 

the Administrator, requesting approval 

to apply an alternative to any 

requirement of §§ 97.630 through 97.634 

or paragraph (5)(i) or (ii) of the 

definition of ‘‘owner’s share’’ in 

§ 97.602. 

(b) A petition submitted under 

paragraph (a) of this section shall 

include sufficient information for the 

evaluation of the petition, including, at 

a minimum, the following information: 

(i) Identification of each unit and 

source covered by the petition; 

(ii) A detailed explanation of why the 

proposed alternative is being suggested 

in lieu of the requirement; 

(iii) A description and diagram of any 

equipment and procedures used in the 

proposed alternative; 

(iv) A demonstration that the 

proposed alternative is consistent with 

the purposes of the requirement for 

which the alternative is proposed and 

with the purposes of this subpart and 

part 75 of this chapter and that any 

adverse effect of approving the 

alternative will be de minimis; and 

(v) Any other relevant information 

that the Administrator may require. 

(c) Use of an alternative to any 

requirement referenced in paragraph (a) 

of this section is in accordance with this 

subpart only to the extent that the 

petition is approved in writing by the 

Administrator and that such use is in 

accordance with such approval. 

§ 97.640 General requirements for TR SO2

Group 1 opt-in units. 

(a) A TR SO2 Group 1 opt-in unit must 

be a unit that: 

(1) Is located in a State; 

(2) Is not a TR SO2 Group 1 unit under 

§ 97.604; 

(3) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; and 

(4) Vents all of its emissions to a stack 

and can meet the monitoring, 

recordkeeping, and reporting 

requirements of this subpart. 

(b) A TR SO2 Group 1 opt-in unit shall 

be deemed to be a TR SO2 Group 1 unit 

for purposes of applying this subpart, 

except for §§ 97.605, 97.611, and 97.612. 

(c) Solely for purposes of applying the 

requirements of §§ 97.613 through 

97.618 and §§ 97.630 through 97.635, a 

unit for which a TR opt-in application 

is submitted and not withdrawn and is 

not yet approved or disapproved under 

§ 97.642 shall be deemed to be a TR SO2

Group 1 unit. 

(d) Any TR SO2 Group 1 opt-in unit, 

and any unit for which a TR opt-in 

application is submitted and not 

withdrawn and is not yet approved or 

disapproved under § 97.642, located at 

the same source as one or more TR SO2

Group 1 units shall have the same 

designated representative and alternate 

designated representative as such TR 

SO2 Group 1 units. 

§ 97.641 Opt-in process. 

A unit meeting the requirements for a 

TR SO2 Group 1 opt-in unit in 

§ 97.640(a) may become a TR SO2 Group 

1 opt-in unit only if, in accordance with 

this section, the designated 

representative of the unit submits a 

complete TR opt-in application for the 

unit and the Administrator approves the 

application. 

(a) Applying to opt-in. The designated 

representative of the unit may submit a 

complete TR opt-in application for the 

unit at any time, except as provided 

under § 97.642(e). A complete TR opt-in 

application shall include the following 

elements in a format prescribed by the 

Administrator: 

(1) Identification of the unit and the 

source where the unit is located, 


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including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, and unit identification 

number and type; 

(2) A certification that the unit: 

(i) Is not a TR SO2 Group 1 unit under 

§ 97.604; 

(ii) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(iii) Vents all of its emissions to a 

stack; and 

(iv) Has documented heat input 

(greater than 0 mmBtu) for more than 

876 hours during the 6 months 

immediately preceding submission of 

the TR opt-in application; 

(3) A monitoring plan in accordance 

with §§ 97.630 through 97.635; 

(4) A statement that the unit, if 

approved to become a TR SO2 Group 1 

unit under paragraph (g) of this section, 

may withdraw from the TR SO2 Group 

1 Trading Program only in accordance 

with § 97.642; 

(5) A statement that the unit, if 

approved to become a TR SO2 Group 1 

unit under paragraph (g) of this section, 

is subject to, and the owners and 

operators of the unit must comply with, 

the requirements of § 97.643; 

(6) A complete certificate of 

representation under § 97.616 consistent 

with § 97.640, if no designated 

representative has been previously 

designated for the source that includes 

the unit; and 

(7) The signature of the designated 

representative and the date signed. 

(b) Interim review of monitoring plan. 

The Administrator will determine, on 

an interim basis, the sufficiency of the 

monitoring plan submitted under 

paragraph (a)(3) of this section. The 

monitoring plan is sufficient, for 

purposes of interim review, if the plan 

appears to contain information 

demonstrating that the SO2 emission 

rate and heat input of the unit and all 

other applicable parameters are 

monitored and reported in accordance 

with §§ 97.630 through 97.635. A 

determination of sufficiency shall not be 

construed as acceptance or approval of 

the monitoring plan. 

(c) Monitoring and reporting. (1)(i) If 

the Administrator determines that the 

monitoring plan is sufficient under 

paragraph (b) of this section, the owner 

or operator of the unit shall monitor and 

report the SO2 emission rate and the 

heat input of the unit and all other 

applicable parameters, in accordance 

with §§ 97.630 through 97.635, starting 

on the date of certification of the 

necessary monitoring systems under 

§§ 97.630 through 97.635 and 

continuing until the TR opt-in 

application submitted under paragraph 

(a) of this section is disapproved under 

this section or, if such TR opt-in 

application is approved, the date and 

time when the unit is withdrawn from 

the TR SO2 Group 1 Trading Program in 

accordance with § 97.642. 

(ii) The monitoring and reporting 

under paragraph (c)(1)(i) of this section 

shall cover the entire control period 

immediately before the date on which 

the unit enters the TR SO2 Group 1 

Trading Program under paragraph (h) of 

this section, during which period 

monitoring system availability must not 

be less than 98 percent under §§ 97.630 

through 97.635 and the unit must be in 

full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(2) To the extent the SO2 emission 

rate and the heat input of the unit are 

monitored and reported in accordance 

with §§ 97.630 through 97.635 for one or 

more entire control periods, in addition 

to the control period under paragraph 

(c)(1)(ii) of this section, during which 

control periods monitoring system 

availability is not less than 98 percent 

under §§ 97.630 through 97.635 and the 

unit is in full compliance with any 

applicable State or Federal emissions or 

emissions-related requirements and 

which control periods begin not more 

than 3 years before the unit enters the 

TR SO2 Group 1 Trading Program under 

paragraph (h) of this section, such 

information shall be used as provided in 

paragraphs (e) and (f) of this section. 

(d) Statement on compliance. After 

submitting to the Administrator all 

quarterly reports required for the unit 

under paragraph (c) of this section, the 

designated representative shall submit, 

in a format prescribed by the 

Administrator, to the Administrator a 

statement that, for the years covered by 

such quarterly reports, the unit was in 

full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(e) Baseline heat input. The unit’s 

baseline heat input shall equal: 

(1) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for only one entire control period, in 

accordance with paragraph (c) of this 

section, the unit’s total heat input (in 

mmBtu) for such control period; or 

(2) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, the average of the amounts of 

the unit’s total heat input (in mmBtu) 

for such control periods. 

(f) Baseline SO2 emission rate. The 

unit’s baseline SO2 emission rate shall 

equal: 

(1) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for only one entire control period, in 

accordance with paragraph (c) of this 

section, the unit’s SO2 emission rate (in 

lb/mmBtu) for such control period; 

(2) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit does not have addon SO2 emission controls during any 

such control periods, the average of the 

amounts of the unit’s SO2 emission rate 

(in lb/mmBtu) for such control periods; 

or 

(3) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit has add-on SO2

emission controls during any such 

control periods, the average of the 

amounts of the unit’s SO2 emission rate 

(in lb/mmBtu) for such control periods 

during which the unit has add-on SO2

emission controls. 

(g) Review of TR opt-in application. 

(1) After the designated representative 

submits the complete TR opt-in 

application, quarterly reports, and 

statement required in paragraphs (a), (c), 

and (d) of this section and if the 

Administrator determines that the 

designated representative shows that the 

unit meets the requirements for a TR 

SO2 Group 1 opt-in unit in § 97.640, the 

element certified in paragraph (a)(2)(iv) 

of this section, and the monitoring and 

reporting requirements of paragraph (c) 

of this section, the Administrator will 

issue a written approval of the TR optin application for the unit. The written 

approve will state the unit’s baseline 

heat input and baseline SO2 emission 

rate. The Administrator will thereafter 

establish a compliance account for the 

source that includes the unit unless the 

source already has a compliance 

account. 

(2) Notwithstanding paragraphs (a) 

through (f) of this section, if, at any time 

before the TR opt-in application is 

approved under paragraph (g)(1) of this 

section, the Administrator determines 

that the unit cannot meet the 

requirements for a TR SO2 Group 1 

opt-in unit in § 97.640, the element 

certified in paragraph (a)(2)(iv) of this 

section, or the monitoring and reporting 

requirements in paragraph (c) of this 

section, the Administrator will issue a 

written disapproval of the TR opt-in 

application for the unit. 

(h) Date of entry into TR SO2 Group 

1 Trading Program. A unit for which a 


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45440 Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules 

TR opt-in application is approved under 

paragraph (g)(1) of this section shall 

become a TR SO2 Group 1 opt-in unit, 

and a TR SO2 Group 1 unit, effective as 

of the later of January 1, 2012, or 

January 1 of the first control period 

during which such approval is issued. 

§ 97.642 Withdrawal of TR SO2 Group 1 

opt-in unit from TR SO2 Group 1 Trading 

Program. 

A TR SO2 Group 1 opt-in unit may 

withdraw from the TR SO2 Group 1 

Trading Program only if, in accordance 

with this section, the designated 

representative of the unit submits a 

request to withdraw the unit and the 

Administrator issues a written approval 

of the request. 

(a) Requesting withdrawal. In order to 

withdraw the TR SO2 Group 1 opt-in 

unit from the TR SO2 Group 1 Trading 

Program, the designated representative 

of the unit shall submit to the 

Administrator a request to withdraw the 

unit effective as of midnight of 

December 31 of a specified calendar 

year, which date must be at least 4 years 

after December 31 of the year of the 

unit’s entry into the TR SO2 Group 1 

Trading Program under § 97.641(h). The 

request shall be in a format prescribed 

by the Administrator and shall be 

submitted no later than 90 days before 

the requested effective date of 

withdrawal. 

(b) Conditions for withdrawal. Before 

a TR SO2 Group 1 opt-in unit covered 

by the request to withdraw may 

withdraw from the TR SO2 Group 1 

Trading Program, the following 

conditions must be met: 

(1) For the control period ending on 

the date on which the withdrawal is to 

be effective, the source that includes the 

TR SO2 Group 1 opt-in unit must meet 

the requirement to hold TR SO2 Group 

1 allowances under §§ 97.624 and 

97.625 and cannot have any excess 

emissions. 

(2) After the requirement under 

paragraph (b)(1) of this section is met, 

the Administrator will deduct from the 

compliance account of the source that 

includes the TR SO2 Group 1 opt-in unit 

TR SO2 Group 1 allowances equal in 

amount to and allocated for the same or 

a prior control period as any TR SO2

Group 1 allowances allocated to the TR 

SO2 Group 1 opt-in unit under § 97.644 

for any control period after the date on 

which the withdrawal is to be effective. 

If there are no other TR SO2 Group 1 

units at the source, the Administrator 

will close the compliance account, and 

the owners and operators of the TR SO2

Group 1 opt-in unit may submit a TR 

SO2 Group 1 allowance transfer for any 

remaining TR SO2 Group 1 allowances 

to another Allowance Management 

System account in accordance with 

§§ 97.622 and 97.623. 

(c) Approving withdrawal. (1) After 

the requirements for withdrawal under 

paragraphs (a) and (b) of this section are 

met (including deduction of the full 

amount of TR SO2 Group 1 allowances 

required), the Administrator will issue a 

written approval of the request to 

withdraw, which will become effective 

as of midnight on December 31 of the 

calendar year for which the withdrawal 

was requested. The unit covered by the 

request shall continue to be a TR SO2

Group 1 opt-in unit until the effective 

date of the withdrawal and shall comply 

with all requirements under the TR SO2

Group 1 Trading Program concerning 

any control periods for which the unit 

is a TR SO2 Group 1 opt-in unit, even 

if such requirements arise or must be 

complied with after the withdrawal 

takes effect. 

(2) If the requirements for withdrawal 

under paragraphs (a) and (b) of this 

section are not met, the Administrator 

will issue a written disapproval of the 

request to withdraw. The unit covered 

by the request shall continue to be a TR 

SO2 Group 1 opt-in unit. 

(d) Reapplication upon failure to meet 

conditions of withdrawal. If the 

Administrator disapproves the request 

to withdraw, the designated 

representative of the unit may submit 

another request to withdraw in 

accordance with paragraphs (a) and (b) 

of this section. 

(e) Ability to reapply to the TR SO2

Group 1 Trading Program. Once a TR 

SO2 Group 1 opt-in unit withdraws from 

the TR SO2 Group 1 Trading Program, 

the designated representative may not 

submit another opt-in application under 

§ 97.641 for such unit before the date 

that is 4 years after the date on which 

the withdrawal became effective. 

§ 97.643 Change in regulatory status. 

(a) Notification. If a TR SO2 Group 1 

opt-in unit becomes a TR SO2 Group 1 

unit under § 97.604, then the designated 

representative of the unit shall notify 

the Administrator in writing of such 

change in the TR SO2 Group 1 opt-in 

unit’s regulatory status, within 30 days 

of such change. 

(b) Administrator’s actions. (1) If a TR 

SO2 Group 1 opt-in unit becomes a TR 

SO2 Group 1 unit under § 97.604, the 

Administrator will deduct, from the 

compliance account of the source that 

includes the TR SO2 Group 1 opt-in unit 

that becomes a TR SO2 Group 1 unit 

under § 97.604, TR SO2 Group 1 

allowances equal in amount to and 

allocated for the same or a prior control 

period as: 

(i) Any TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 opt-in 

unit under § 97.644 for any control 

period starting after the date on which 

the TR SO2 Group 1 opt-in unit becomes 

a TR SO2 Group 1 unit under § 97.604; 

and 

(ii) If the date on which the TR SO2

Group 1 opt-in unit becomes a TR SO2

Group 1 unit under § 97.604 is not 

December 31, the TR SO2 Group 1 

allowances allocated to the TR SO2

Group 1 opt-in unit under § 97.644 for 

the control period that includes the date 

on which the TR SO2 Group 1 opt-in 

unit becomes a TR SO2 Group 1 unit 

under § 97.604— 

(A) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

SO2 Group 1 opt-in unit becomes a TR 

SO2 Group 1 unit under § 97.604, 

divided by the total number of days in 

the control period, and 

(B) Rounded to the nearest allowance. 

(2) The designated representative 

shall ensure that the compliance 

account of the source that includes the 

TR SO2 Group 1 opt-in unit that 

becomes a TR SO2 Group 1 unit under 

§ 97.604 contains the TR SO2 Group 1 

allowances necessary for completion of 

the deduction under paragraph (b)(1) of 

this section. 

(3)(i) For control periods starting after 

the date on which the TR SO2 Group 1 

opt-in unit becomes a TR SO2 Group 1 

unit under § 97.604, the TR SO2 Group 

1 opt-in unit will be allocated TR SO2

Group 1 allowances in accordance with 

§ 97.612. 

(ii) If the date on which the TR SO2

Group 1 opt-in unit becomes a TR SO2

Group 1 unit under § 97.604 is not 

December 31, the following amount of 

TR SO2 Group 1 allowances will be 

allocated to the TR SO2 Group 1 opt-in 

unit (as a TR SO2 Group 1 unit) in 

accordance with § 97.612 for the control 

period that includes the date on which 

the TR SO2 Group 1 opt-in unit becomes 

a TR SO2 Group 1 unit under § 97.604: 

(A) The amount of TR SO2 Group 1 

allowances otherwise allocated to the 

TR SO2 Group 1 opt-in unit (as a TR SO2

Group 1 unit) in accordance with 

§ 97.612 for the control period; 

(B) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

SO2 Group 1 opt-in unit becomes a TR 

SO2 Group 1 unit under § 97.604, 

divided by the total number of days in 

the control period; and 

(C) Rounded to the nearest allowance. 


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§ 97.644 TR SO2 Group 1 allowance 

allocations to TR SO2 Group 1 opt-in units. 

(a) Timing requirements. (1) When the 

TR opt-in application is approved for a 

unit under § 97.641(g), the 

Administrator will issue TR SO2 Group 

1 allowances and allocate them to the 

unit for the control period in which the 

unit enters the TR SO2 Group 1 Trading 

Program under § 97.641(h), in 

accordance with paragraph (b) of this 

section. 

(2) By no later than October 31 of the 

control period after the control period in 

which a TR SO2 Group 1 opt-in unit 

enters the TR SO2 Group 1 Trading 

Program under § 97.641(h) and October 

31 of each year thereafter, the 

Administrator will issue TR SO2 Group 

1 allowances and allocate them to the 

TR SO2 Group 1 opt-in unit for the 

control period that includes such 

allocation deadline and in which the 

unit is a TR SO2 Group 1 opt-in unit, in 

accordance with paragraph (b) of this 

section. 

(b) Calculation of allocation. For each 

control period for which a TR SO2

Group 1 opt-in unit is to be allocated TR 

SO2 Group 1 allowances, the 

Administrator will issue and allocate TR 

SO2 Group 1 allowances in accordance 

with the following procedures: 

(1) The heat input (in mmBtu) used 

for calculating the TR SO2 Group 1 

allowance allocation will be the lesser 

of: 

(i) The TR SO2 Group 1 opt-in unit’s 

baseline heat input determined under 

§ 97.641(g); or 

(ii) The TR SO2 Group 1 opt-in unit’s 

heat input, as determined in accordance 

with §§ 97.630 through 97.635, for the 

immediately prior control period, 

except when the allocation is being 

calculated for the control period in 

which the TR SO2 Group 1 opt-in unit 

enters the TR SO2 Group 1 Trading 

Program under § 97.641(h). 

(2) The SO2 emission rate (in lb/ 

mmBtu) used for calculating TR SO2

Group 1 allowance allocations will be 

the lesser of: 

(i) The TR SO2 Group 1 opt-in unit’s 

baseline SO2 emission rate (in lb/ 

mmBtu) determined under § 97.641(g) 

and multiplied by 70 percent; or 

(ii) The most stringent State or 

Federal SO2 emissions limitation 

applicable to the TR SO2 Group 1 optin unit at any time during the control 

period for which TR SO2 Group 1 

allowances are to be allocated. 

(3) The Administrator will issue TR 

SO2 Group 1 allowances and allocate 

them to the TR SO2 Group 1 opt-in unit 

in an amount equaling the heat input 

under paragraph (b)(1) of this section, 

multiplied by the SO2 emission rate 

under paragraph (b)(2) of this section, 

divided by 2,000 lb/ton, and rounded to 

the nearest allowance. 

(c) Recordation. (1) The Administrator 

will record, in the compliance account 

of the source that includes the TR SO2

Group 1 opt-in unit, the TR SO2 Group 

1 allowances allocated to the TR SO2

Group 1 opt-in unit under paragraph 

(a)(1) of this section. 

(2) By December 1 of the control 

period after the control period in which 

a TR SO2 Group 1 opt-in unit enters the 

TR SO2 Group 1 Trading Program under 

§ 97.641(h) and December 1 of each year 

thereafter, the Administrator will 

record, in the compliance account of the 

source that includes the TR SO2 Group 

1 opt-in unit, the TR SO2 Group 1 

allowances allocated to the TR SO2

Group 1 opt-in unit under paragraph 

(a)(2) of this section. 

38. Part 97 is amended by adding 

subpart DDDDD to read as follows: 

Subpart DDDDD—TR SO2 Group 2 Trading 

Program 

Sec. 

97.701 Purpose. 

97.702 Definitions. 

97.703 Measurements, abbreviations, and 

acronyms. 

97.704 Applicability. 

97.705 Retired unit exemption. 

97.706 Standard requirements. 

97.707 Computation of time. 

97.708 Administrative appeal procedures. 

97.709 [Reserved] 

97.710 State SO2 Group 2 trading budgets, 

new-unit set-asides, and variability 

limits. 

97.711 Timing requirements for TR SO2

Group 2 allowance allocations. 

97.712 TR SO2 Group 2 allowance 

allocations for new units. 

97.713 Authorization of designated 

representative and alternate designated 

representative. 

97.714 Responsibilities of designated 

representative and alternate designated 

representative. 

97.715 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.716 Certificate of representation. 

97.717 Objections concerning designated 

representative and alternate designated 

representative. 

97.718 Delegation by designated 

representative and alternate designated 

representative. 

97.719 [Reserved] 

97.720 Establishment of Allowance 

Management System accounts. 

97.721 Recordation of TR SO2 Group 2 

allowance allocations. 

97.722 Submission of TR SO2 Group 2 

allowance transfers. 

97.723 Recordation of TR SO2 Group 2 

allowance transfers. 

97.724 Compliance with TR SO2 Group 2 

emissions limitation. 

97.725 Compliance with TR SO2 Group 2 

assurance provisions. 

97.726 Banking. 

97.727 Account error. 

97.728 Administrator’s action on 

submissions. 

97.729 [Reserved] 

97.730 General monitoring, recordkeeping, 

and reporting requirements. 

97.731 Initial monitoring system 

certification and recertification 

procedures. 

97.732 Monitoring system out-of-control 

periods. 

97.733 Notifications concerning 

monitoring. 

97.734 Recordkeeping and reporting. 

97.735 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

97.740 General requirements for TR SO2

Group 2 opt-in units. 

97.741 Opt-in process. 

97.742 Withdrawal of TR SO2 Group 2 optin unit from TR SO2 Group 2 Trading 

Program. 

97.743 Change in regulatory status. 

97.744 TR SO2 Group 2 allowance 

allocations to TR SO2 Group 2 opt-in 

units. 

Subpart DDDDD—TR SO2 Group 2 

Trading Program 

§ 97.701 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) SO2 Group 2 

Trading Program, under section 110 of 

the Clean Air Act and § 52.38(b) of this 

chapter, as a means of mitigating 

interstate transport of fine particulates 

and nitrogen oxides. 

§ 97.702 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor) of the United 

States Environmental Protection 

Agency, the Administrator’s duly 

authorized representative under this 

subpart. 

Allocate or allocation means, with 

regard to TR SO2 Group 2 allowances, 

the determination by the Administrator 

of the amount of such TR SO2 Group 2 

allowances to be initially credited to a 

TR SO2 Group 2 source or a new unit 

set-aside. 

Allowable SO2 emission rate means, 

with regard to a unit, the SO2 emission 

rate limit that is applicable to the unit 


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and covers the longest averaging period 

not exceeding one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR SO2

Group 2 allowances under the TR SO2

Group 2 Trading Program. Such 

allowances are allocated, held, 

deducted, or transferred only as whole 

allowances. The Allowance 

Management System is a component of 

the CAMD Business System, which is 

the system used by the Administrator to 

handle TR SO2 Group 2 allowances and 

data related to SO2 emissions. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

SO2 Group 2 allowances. 

Allowance transfer deadline means, 

for a control period, midnight of March 

1 (if it is a business day), or midnight 

of the first business day thereafter (if 

March 1 is not a business day), 

immediately after such control period 

and is the deadline by which a TR SO2

Group 2 allowance transfer must be 

submitted for recordation in a TR SO2

Group 2 source’s compliance account in 

order to be available for use in 

complying with the source’s TR SO2

Group 2 Annual emissions limitation for 

such control period in accordance with 

§ 97.724. 

Alternate designated representative 

means, for a TR SO2 Group 2 source and 

each TR SO2 Group 2 unit at the source, 

the natural person who is authorized by 

the owners and operators of the source 

and all such units at the source, in 

accordance with this subpart, to act on 

behalf of the designated representative 

in matters pertaining to the TR SO2

Group 2 Trading Program. If the TR SO2

Group 2 source is also subject to the 

Acid Rain Program, TR NOX Annual 

Season Trading Program, or TR NOX

Ozone Season Trading Program, then 

this natural person shall be the same 

natural person as the alternate 

designated representative as defined in 

§ 72.2 of this chapter, § 97.402, or 

§ 97.502 respectively. 

Authorized account representative 

means, with regard to a general account, 

the natural person who is authorized, in 

accordance with this subpart, to transfer 

and otherwise dispose of TR SO2 Group 

2 allowances held in the general 

account and, with regard to a TR SO2

Group 2 source’s compliance account, 

the designated representative of the 

source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 

(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

Certifying official means a natural 

person who is: 

(1) For a corporation, a president, 

secretary, treasurer, or vice-president or 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy or decision 

making functions for the corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Coal-fired means combusting any 

amount of coal or coal-derived fuel, 

alone or in combination with any 

amount of any other fuel, during 1990 

or any year thereafter. 

Cogeneration system means an 

integrated group, at a source, of 

equipment (including a boiler, or 

combustion turbine, and a steam turbine 

generator) designed to produce useful 

thermal energy for industrial, 

commercial, heating, or cooling 

purposes and electricity through the 

sequential use of energy. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine— 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing during the later of 1990 

or the 12-month period starting on the 

date that the unit first produces 

electricity and during each calendar 

year after the later of 1990 or the 

calendar year in which the unit first 

produces electricity— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle unit, useful 

power not less than 45 percent of total 

energy input; 

(3) Provided that the total energy 

input under paragraphs (2)(i)(B) and 

(2)(ii) of this definition shall equal the 

unit’s total energy input from all fuel, 

except biomass if the unit is a boiler; 

and 

(4) Provided that, if a topping-cycle 

unit is operated as part of a cogeneration 

system during a calendar year and the 

cogeneration system meets on a systemwide basis the requirement in paragraph 

(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such 

requirement during that calendar year. 

Combustion turbine means an 

enclosed device comprising: 

(1) If the device is simple cycle, a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the device is combined cycle, 

the equipment described in paragraph 

(1) of this definition and any associated 


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duct burner, heat recovery steam 

generator, and steam turbine. 

Commence commercial operation 

means, with regard to a unit: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 97.705. 

(i) For a unit that is a TR SO2 Group 

2 unit under § 97.704 on the later of 

November 15, 1990 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit that is a TR SO2 Group 

2 unit under § 97.704 on the later of 

November 15, 1990 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source, such date shall remain the 

replaced unit’s date of commencement 

of commercial operation, and the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 97.705, for a unit that is not a TR 

SO2 Group 2 unit under § 97.704 on the 

later of November 15, 1990 or the date 

the unit commences commercial 

operation as defined in introductory text 

of paragraph (1) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a TR SO2

Group 2 unit under § 97.704. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that subsequently undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source), 

such date shall remain the date of 

commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that is subsequently replaced by a 

unit at the same source, such date shall 

remain the replaced unit’s date of 

commencement of commercial 

operation, and the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

Commence operation means, with 

regard to a unit: 

(1) To have begun any mechanical, 

chemical, or electronic process, 

including start-up of the unit’s 

combustion chamber. 

(2) For a unit that undergoes a 

physical change (other than replacement 

of the unit by a unit at the same source) 

after the date the unit commences 

operation as defined in paragraph (1) of 

this definition, such date shall remain 

the date of commencement of operation 

of the unit, which shall continue to be 

treated as the same unit. 

(3) For a unit that is replaced by a unit 

at the same source after the date the unit 

commences operation as defined in 

paragraph (1) of this definition, such 

date shall remain the replaced unit’s 

date of commencement of operation, 

and the replacement unit shall be 

treated as a separate unit with a separate 

date for commencement of operation as 

defined in paragraph (1), (2), or (3) of 

this definition as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR SO2 Group 2 

source under this subpart, in which any 

TR SO2 Group 2 allowance allocations 

for the TR SO2 Group 2 units at the 

source are recorded and in which are 

held any TR SO2 Group 2 allowances 

available for use for a control period in 

complying with the source’s TR SO2

Group 2 emissions limitation in 

accordance with § 97.724 and the TR 

SO2 Group 2 assurance provisions in 

accordance with § 97.725. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of SO2 emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.730 

through 97.735. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A SO2 monitoring system, 

consisting of a SO2 pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of SO2

emissions, in parts per million (ppm); 

(3) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(4) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(5) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting January 1 of a calendar year, 

except as provided in § 97.706(c)(3), and 

ending on December 31 of the same 

year, inclusive. 

Designated representative means, for 

a TR SO2 Group 2 source and each TR 

SO2 Group 2 unit at the source, the 

natural person who is authorized by the 

owners and operators of the source and 

all such units at the source, in 

accordance with this subpart, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

TR SO2 Group 2 Trading Program. If the 

TR SO2 Group 2 source is also subject 

to the Acid Rain Program, TR NOX

Annual Trading Program, or TR NOX

Ozone Season Trading Program, then 

this natural person shall be the same 

natural person as the designated 

representative, as defined in § 72.2 of 

this chapter, § 97.402, or § 97.502 

respectively. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart. 

Excess emissions means any ton of 

SO2 emitted from the TR SO2 Group 2 

units at a TR SO2 Group 2 source during 

a control period that exceeds the TR SO2

Group 2 emissions limitation for the 

source. 

Fossil fuel means— 


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(1) Natural gas, petroleum, coal, or 

any form of solid, liquid, or gaseous fuel 

derived from such material; or 

(2) For purposes of applying 

§§ 97.704(b)(2)(i)(B), 97.704(b)(2)(ii)(B), 

and 97.704(b)(2)(iii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 1990 or any calendar year 

thereafter. 

Fuel oil means any petroleum-based 

fuel (including diesel fuel or petroleum 

derivatives such as oil tar) and any 

recycled or blended petroleum products 

or petroleum by-products used as a fuel 

whether in a liquid, solid, or gaseous 

state. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a unit, electricity made 

available for use, including any such 

electricity used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Heat input means, with regard to a 

unit for a specified period of time, the 

product (in mmBtu/time) of the gross 

calorific value of the fuel (in mmBtu/lb) 

multiplied by the fuel feed rate into a 

combustion device (in lb of fuel/time), 

as measured, recorded, and reported to 

the Administrator by the designated 

representative and as modified by the 

Administrator in accordance with this 

subpart and excluding the heat derived 

from preheated combustion air, 

recirculated flue gases, or exhaust. 

Heat input rate means the amount of 

heat input (in mmBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means 

the maximum amount of fuel per hour 

(in Btu/hr) that a unit is capable of 

combusting on a steady state basis as of 

the initial installation of the unit as 

specified by the manufacturer of the 

unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as of such 

installation as specified by the 

manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as of such completion as 

specified by the person conducting the 

physical change. 

Newly affected TR SO2 Group 2 unit 

means a unit that was not a TR SO2

Group 2 unit when it began operating 

but that thereafter becomes a TR SO2

Group 2 unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means any person who 

operates, controls, or supervises a TR 

SO2 Group 2 unit or a TR SO2 Group 2 

source and shall include, but not be 

limited to, any holding company, utility 

system, or plant manager of such a unit 

or source. 

Owner means, with regard to a TR SO2

Group 2 source or a TR SO2 Group 2 

unit at a source respectively, any of the 

following persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR SO2

Group 2 unit at the source or the TR SO2

Group 2 unit; 

(2) Any holder of a leasehold interest 

in a TR SO2 Group 2 unit at the source 

or the TR SO2 Group 2 unit, provided 

that, unless expressly provided for in a 

leasehold agreement, ‘‘owner’’ shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such TR 

SO2 Group 2 unit; 

(3) Any purchaser of power from a TR 

SO2 Group 2 unit at the source or the 

TR SO2 Group 2 unit under a life-of-theunit, firm power contractual 

arrangement; 

(4) Provided that, for purposes of 

applying the TR SO2 Group 2 assurance 

provisions in §§ 97.706(c)(2) and 97.725, 

if one or more owners (as defined in 

paragraphs (1) through (3) of this 

definition) of one or more TR SO2 Group 

2 units in a State are wholly owned by 

another, common owner, all such 

owners shall be treated collectively as a 

single owner in the State. 

Owner’s assurance level means: 

(1) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.706(c)(2)(iii)(A) and not as 

described in § 97.706(c)(2)(iii)(B), the 

owner’s share of the State SO2 Group 2 

trading budget with the one-year 

variability limit for the State for such 

control period; or 

(2) With regard to a State and control 

period for which the State assurance 

level is exceeded as described in 

§ 97.706(c)(2)(iii)(B), the owner’s share 

of the State SO2 Group 2 trading budget 

with the three-year variability limit for 

the State for such control period. 

Owner’s share means: 

(1) With regard to a total amount of 

SO2 emissions from all TR SO2 Group 2 

units in a State during a control period, 

the total tonnage of SO2 emissions 

during such control period from all of 

the owner’s TR SO2 Group 2 units in the 

State; 

(2) With regard to a State SO2 Group 

2 trading budget with a one-year 

variability limit for a control period, the 

amount (rounded to the nearest 

allowance) equal to the total amount of 

TR SO2 Group 2 allowances allocated 

for such control period to all of the 

owner’s TR SO2 Group 2 units in the 

State, multiplied by the sum of the State 

SO2 Group 2 trading budget under 

§ 97.710(a) and the State’s one-year 

variability limit under § 97.710(b) and 

divided by such State SO2 Group 2 

trading budget; 

(3) With regard to a State SO2 Group 

2 trading budget with a three-year 


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variability limit for a control period, the 

amount (rounded to the nearest 

allowance) equal to the total amount of 

TR SO2 Group 2 allowances allocated 

for such control period to all of the 

owner’s TR SO2 Group 2 units in the 

State, multiplied by the sum of the State 

SO2 Group 2 trading budget under 

§ 97.710(a) and the State’s three-year 

variability limit under § 97.710(b) and 

divided by such State SO2 Group 2 

trading budget; 

(4) Provided that, in the case of a unit 

with more than one owner, the amount 

of tonnage of SO2 emissions and of TR 

SO2 Group 2 allowances allocated for a 

control period, with regard to such unit, 

used in determining each owner’s share 

shall be the amount (rounded to the 

nearest ton and the nearest allowance) 

equal to the unit’s SO2 emissions and 

allocation of such allowances, 

respectively, for such control period 

multiplied by the percentage of 

ownership in the unit that the owner’s 

legal, equitable, leasehold, or 

contractual reservation or entitlement in 

the unit comprises as of December 31 of 

such control period; 

(5) Provided that, where two or more 

units emit through a common stack that 

is the monitoring location from which 

SO2 mass emissions are reported for a 

control period for a year, the amount of 

tonnage of each unit’s SO2 emissions 

used in determining each owner’s share 

for such control period shall be: 

(i) The amount (rounded to the 

nearest ton) of SO2 emissions reported 

at the common stack multiplied by the 

quotient of such unit’s heat input for 

such control period divided by the total 

heat input reported from the common 

stack for such control period; 

(ii) An amount determined in 

accordance with a methodology that the 

Administrator determines is consistent 

with the purposes of this definition and 

whose adverse effect (if any) the 

Administrator determines will be de 

minimis; or 

(iii) An amount approved by the 

Administrator in response to a petition 

for an alternative requirement submitted 

in accordance with § 97.735; and 

(6) Provided that, in the case of a unit 

that operates during, but is allocated no 

TR SO2 Group 2 allowances for, a 

control period, the unit shall be treated, 

solely for purposes of this definition, as 

being allocated an amount (rounded to 

the nearest allowance) of TR SO2 Group 

2 allowances for such control period 

equal to the lesser of— 

(i) The unit’s allowable SO2 emission 

rate (in lb per MWe) applicable to such 

control period, multiplied by a capacity 

factor of 0.84 (if the unit is a coal-fired 

boiler), 0.15 (if the unit is a simple 

combustion turbine), or 0.66 (if the unit 

is a combined cycle turbine), multiplied 

by the unit’s maximum hourly load as 

reported in accordance with this subpart 

and by 8,760 hours/control period, and 

divided by 2,000 lb/ton; or 

(ii) For a unit listed in appendix A to 

this subpart, the sum of the unit’s SO2

emissions in the control period in the 

last three years during which the unit 

operated during the control period, 

divided by three. 

Permanently retired means, with 

regard to a unit, a unit that is 

unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Potential electrical output capacity 

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/ 

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR SO2 Group 2 

allowances, the moving of TR SO2

Group 2 allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) For a topping-cycle unit, the use 

of reject heat from electricity production 

in a useful thermal energy application 

or process; or 

(2) For a bottoming-cycle unit, the use 

of reject heat from useful thermal energy 

application or process in electricity 

production. 

Serial number means, for a TR SO2

Group 2 allowance, the unique 

identification number assigned to each 

TR SO2 Group 2 allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States or the 

District of Columbia that is subject to 

the TR SO2 Group 2 Trading Program 

pursuant to § 52.38(c) of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline shall 

be determined by the date of dispatch, 

transmission, or mailing and not the 

date of receipt. 

Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means total energy 

of all forms supplied to a unit, 

excluding energy produced by the unit. 

Each form of energy supplied shall be 

measured by the lower heating value of 

that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55 (W + 9H) 

Where 

LHV = lower heating value of the form of 

energy in Btu/lb, 

HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means the sum of 

useful power and useful thermal energy 

produced by the unit. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established by the Administrator in 


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accordance with subpart AAAAA and 

52.37(a) of this chapter, as a means of 

mitigating interstate transport of fine 

particulates and NOX.

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established by the 

Administrator in accordance with 

subpart BBBBB of this part and 52.37(b) 

of this chapter, as a means of mitigating 

interstate transport of ozone and NOX.

TR SO2 Group 2 allowance means a 

limited authorization issued and 

allocated by the Administrator under 

this subpart to emit one ton of SO2

during a control period of the specified 

calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the TR 

SO2 Group 2 Trading Program. 

TR SO2 Group 2 allowance deduction 

or deduct TR SO2 Group 2 allowances 

means the permanent withdrawal of TR 

SO2 Group 2 allowances by the 

Administrator from a compliance 

account, e.g., in order to account for 

compliance with the TR SO2 Group 2 

emissions limitation or assurance 

provisions. 

TR SO2 Group 2 allowances held or 

hold TR SO2 Group 2 allowances means 

the TR SO2 Group 2 allowances treated 

as included in an Allowance 

Management System account as of a 

specified point in time because at that 

time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR SO2 Group 2 allowance 

transfer in accordance with this subpart; 

and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR SO2 Group 2 

allowance transfer in accordance with 

this subpart. 

TR SO2 Group 2 emissions limitation 

means, for a TR SO2 Group 2 source, the 

tonnage of SO2 emissions authorized in 

a control period by the TR SO2 Group 

2 allowances available for deduction for 

the source under § 97.724(a) for such 

control period. 

TR SO2 Group 2 source means a 

source that includes one or more TR 

SO2 Group 2 units. 

TR SO2 Group 2 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established by the Administrator in 

accordance with this subpart and 

52.38(c) of this chapter, as a means of 

mitigating interstate transport of fine 

particulates and SO2.

TR SO2 Group 2 unit means a unit 

that is subject to the TR SO2 Group 2 

Trading Program under § 97.704. 

Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired 

combustion turbine, or other stationary, 

fossil-fuel-fired combustion device. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means electricity or 

mechanical energy that a unit makes 

available for use, excluding any such 

energy used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.703 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.704 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State shall 

be TR SO2 Group 2 units, and any 

source that includes one or more such 

units shall be a TR SO2 Group 2 source, 

subject to the requirements of this 

subpart: Any stationary, fossil-fuel-fired 

boiler or stationary, fossil-fuel-fired 

combustion turbine serving at any time, 

since the later of November 15, 1990 or 

the start-up of the unit’s combustion 

chamber, a generator with nameplate 

capacity of more than 25 MWe 

producing electricity for sale. 

(2) If a stationary boiler or stationary 

combustion turbine that, under 

paragraph (a)(1) of this section, is not a 

TR SO2 Group 2 unit begins to combust 

fossil fuel or to serve a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale, the 

unit shall become a TR SO2 Group 2 

unit as provided in paragraph (a)(1) of 

this section on the first date on which 

it both combusts fossil fuel and serves 

such generator. 

(b) Any unit in a State that otherwise 

is a TR SO2 Group 2 unit under 

paragraph (a) of this section and that 

meets the requirements set forth in 

paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) 

of this section shall not be a TR SO2

Group 2 unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

during the later of 1990 or the 12-month 

period starting on the date the unit first 

produces electricity and continuing to 

qualify as a cogeneration unit; and 

(B) Not serving at any time, since the 

later of November 15, 1990 or the startup of the unit’s combustion chamber, a 

generator with nameplate capacity of 

more than 25 MWe supplying in any 

calendar year more than one-third of the 

unit’s potential electric output capacity 

or 219,000 MWh, whichever is greater, 

to any utility power distribution system 

for sale. 

(ii) If a unit qualifies as a cogeneration 

unit during the later of 1990 or the 

12-month period starting on the date the 

unit first produces electricity and meets 

the requirements of paragraphs (b)(1)(i) 

of this section for at least one calendar 

year, but subsequently no longer meets 

such qualification and requirements, the 

unit shall become a TR SO2 Group 2 

unit starting on the earlier of January 1 

after the first calendar year during 

which the unit first no longer qualifies 

as a cogeneration unit or January 1 after 

the first calendar year during which the 

unit no longer meets the requirements of 

paragraph (b)(1)(i)(B) of this section. 

(2)(i) Any unit commencing operation 

before January 1, 1985: 

(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average annual fuel 

consumption of fossil fuel for 1985– 

1987 less than 20 percent (on a Btu 


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basis) and an average annual fuel 

consumption of fossil fuel for any 3 

consecutive calendar years after 1990 

less than 20 percent (on a Btu basis). 

(ii) Any unit commencing operation 

on or after January 1, 1985: 

(A) Qualifying as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit; and 

(B) With an average annual fuel 

consumption of fossil fuel for the first 

3 calendar years of operation less than 

20 percent (on a Btu basis) and an 

average annual fuel consumption of 

fossil fuel for any 3 consecutive 

calendar years after 1990 less than 20 

percent (on a Btu basis). 

(iii) If a unit qualifies as a solid waste 

incineration unit during the later of 

1990 or the 12-month period starting on 

the date the unit first produces 

electricity and meets the requirements 

of paragraph (b)(2)(i) or (ii) of this 

section for at least 3 consecutive 

calendar years, but subsequently no 

longer meets such qualification and 

requirements, the unit shall become a 

TR SO2 Group 2 unit starting on the 

earlier of January 1 after the first 

calendar year during which the unit first 

no longer qualifies as a solid waste 

incineration unit or January 1 after the 

first 3 consecutive calendar years after 

1990 for which the unit has an average 

annual fuel consumption of fossil fuel of 

20 percent or more. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 

may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR SO2 Group 

2 Trading Program to the unit or other 

equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 

equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the petition shall 

include the following certification 

statement, signed by the certifying 

official: ‘‘I am authorized to make this 

submission on behalf of the owners and 

operators of the unit or other equipment 

for which the submission is made. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) Response. The Administrator will 

issue a written response to the petition 

and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR SO2 Group 

2 Trading Program to the unit or other 

equipment shall be binding on any 

permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.705 Retired unit exemption. 

(a)(1) Any TR SO2 Group 2 unit that 

is permanently retired and is not a TR 

SO2 Group 2 opt-in unit shall be exempt 

from § 97.706(b) and (c)(1), § 97.724, 

and §§ 97.730 through 97.735. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR SO2

Group 2 unit is permanently retired. 

Within 30 days of the unit’s permanent 

retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any SO2, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

SO2 Group 2 Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 

§ 97.706 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.713 through 97.718. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each TR 

SO2 Group 2 source and each TR SO2

Group 2 unit at the source shall comply 

with the monitoring, reporting, and 

recordkeeping requirements of §§ 97.730 

through 97.735. 

(2) The emissions data determined in 

accordance with §§ 97.730 through 

97.735 shall be used to calculate 

allocations of TR SO2 Group 2 

allowances under §§ 97.711(a)(2) and (b) 

and 97.712 and to determine 

compliance with the TR SO2 Group 2 

emissions limitation and assurance 

provisions under paragraph (c) of this 

section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.730 through 97.735 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) SO2 emissions requirements. (1) 

TR SO2 Group 2 emissions limitation. (i) 

As of the allowance transfer deadline for 

a control period, the owners and 

operators of each TR SO2 Group 2 

source and each TR SO2 Group 2 unit 

at the source shall hold, in the source’s 

compliance account, TR SO2 Group 2 

allowances available for deduction for 

such control period under § 97.724(a) in 

an amount not less than the tons of total 

SO2 emissions for such control period 

from all TR SO2 Group 2 units at the 

source. 


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(ii) If a TR SO2 Group 2 source emits 

SO2 during any control period in excess 

of the TR SO2 Group 2 emissions 

limitation set forth in paragraph (c)(1)(i) 

of this section, then: 

(A) The owners and operators of the 

source and each TR SO2 Group 2 unit 

at the source shall hold the TR SO2

Group 2 allowances required for 

deduction under § 97.724(d) and pay 

any fine, penalty, or assessment or 

comply with any other remedy imposed, 

for the same violations, under the Clean 

Air Act; and 

(B) Each ton of such excess emissions 

and each day of such control period 

shall constitute a separate violation of 

this subpart and the Clean Air Act. 

(2) TR SO2 Group 2 assurance 

provisions. (i) If the total amount of SO2

emissions from all TR SO2 Group 2 

units in a State during a control period 

in 2014 or any year thereafter exceeds 

the State assurance level as described in 

paragraph (c)(2)(iii) of this section, then 

each owner whose share of such SO2

emissions during such control period 

exceeds the owner’s assurance level for 

the State and such control period shall 

hold, in a compliance account 

designated by the owner in accordance 

with § 97.725(b)(4)(ii), TR SO2 Group 2 

allowances available for deduction for 

such control period under § 97.725(a) in 

an amount equal to the product, as 

determined by the Administrator in 

accordance with § 97.725(b), of 

multiplying— 

(A) The quotient (rounded to the 

nearest whole number) of the amount by 

which the owner’s share of such SO2

emissions exceeds the owner’s 

assurance level divided by the sum of 

the amounts, determined for all such 

owners, by which each owner’s share of 

such SO2 emissions exceeds that 

owner’s assurance level; and 

(B) The amount by which total SO2

emissions for all TR SO2 Group 2 units 

in the State for such control period 

exceed the State assurance level as 

determined in accordance with 

paragraph (c)(2)(iii) of this section. 

(ii) The owner shall hold the TR SO2

Group 2 allowances required under 

paragraph (c)(2)(i) of this section, as of 

midnight of November 1 (if it is a 

business day), or midnight of the first 

business day thereafter (if November 1 

is not a business day), immediately after 

such control period. 

(iii) The total amount of SO2

emissions from all TR SO2 Group 2 

units in a State during a control period 

in 2014 or any year thereafter exceeds 

the State assurance level: 

(A) If such total amount of SO2

emissions exceeds the sum, for such 

control period, of the State SO2 Group 

2 trading budget and the State’s oneyear variability limit under § 97.710(b); 

or 

(B) If, with regard to a control period 

in 2016 or any year thereafter, the sum, 

divided by three, of such total amount 

of SO2 emissions and the total amounts 

of SO2 emissions from all TR SO2 Group 

2 units in the State during the control 

periods in the immediately preceding 

two years exceeds the sum, for such 

control period, of the State SO2 Group 

2 trading budget and the State’s threeyear variability limit under § 97.710(b); 

(C) Provided that the amount by 

which such total amount of SO2

emissions exceeds the State assurance 

level shall be the greater of the amounts 

of the exceedance calculated under 

paragraph (c)(2)(iii)(A) of this section 

and under paragraph (c)(2)(iii)(B) of this 

section. 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if the 

total amount of SO2 emissions from all 

TR SO2 Group 2 units in a State during 

a control period exceeds the State 

assurance level or if an owner’s share of 

total SO2 emissions from the TR SO2

Group 2 units in a State during a control 

period exceeds the owner’s assurance 

level. 

(v) To the extent an owner fails to 

hold TR SO2 Group 2 allowances for a 

control period in accordance with 

paragraphs (c)(2)(i) and (ii) of this 

section, 

(A) The owner shall pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed under the 

Clean Air Act; and 

(B) Each TR SO2 Group 2 allowance 

that the owner fails to hold for a control 

period in accordance with paragraphs 

(c)(2)(i) and (ii) of this section and each 

day of such control period shall 

constitute a separate violation of this 

subpart and the Clean Air Act. 

(3) Compliance periods. A TR SO2

Group 2 unit shall be subject to the 

requirements: 

(i) Under paragraph (c)(1) of this 

section for the control period starting on 

the later of January 1, 2012 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.730(b) and for each control period 

thereafter; and 

(ii) Under paragraph (c)(2) of this 

section for the control period starting on 

the later of January 1, 2014 or the 

deadline for meeting the unit’s monitor 

certification requirements under 

§ 97.730(b) and for each control period 

thereafter. 

(4) Vintage of deducted allowances. A 

TR SO2 Group 2 allowance shall not be 

deducted, for compliance with the 

requirements under paragraphs (c)(1) 

and (2) of this section, for a control 

period in a calendar year before the year 

for which the TR SO2 Group 2 

allowance was allocated. 

(5) Allowance Management System 

requirements. Each TR SO2 Group 2 

allowance shall be held in, deducted 

from, or transferred into, out of, or 

between Allowance Management 

System accounts in accordance with 

this subpart. 

(6) Limited authorization. (i) A TR 

SO2 Group 2 allowance is a limited 

authorization to emit one ton of SO2 in 

accordance with the TR SO2 Group 2 

Trading Program. 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit such authorization to 

the extent the Administrator determines 

is necessary or appropriate to 

implement any provision of the Clean 

Air Act. 

(7) Property right. A TR SO2 Group 2 

allowance does not constitute a property 

right. 

(d) Title V Permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of TR SO2 Group 2 

allowances in accordance with this 

subpart. 

(2) A description of whether a unit is 

required to monitor and report SO2

emissions using a continuous emission 

monitoring system (under §§ 75.10, 

75.11, and 75.16 of this chapter), an 

excepted monitoring system (under 

appendix D to part 75 of this chapter), 

a low mass emissions excepted 

monitoring methodology (under § 75.19 

of this chapter), or an alternative 

monitoring system (under subpart E of 

part 75 of this chapter) in accordance 

with §§ 97.730 through 97.735 may be 

added to, or changed in, a title V permit 

using minor permit modification 

procedures in accordance with 

§§ 70.7(e)(2) and 71.7(e)(1) of this 

chapter, provided that the requirements 

applicable to the described monitoring 

and reporting (as added or changed, 

respectively) are already incorporated in 

such permit. This paragraph explicitly 

provides that the addition of, or change 

to, a unit’s description as described in 

the prior sentence is eligible for minor 

permit modification procedures in 

accordance with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. (1) Unless 

otherwise provided, the owners and 

operators of each TR SO2 Group 2 

source and each TR SO2 Group 2 unit 

at the source shall keep on site at the 

source each of the following documents 

(in hardcopy or electronic format) for a 


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period of 5 years from the date the 

document is created. This period may 

be extended for cause, at any time 

before the end of 5 years, in writing by 

the Administrator. 

(i) The certificate of representation 

under § 97.716 for the designated 

representative for the source and each 

TR SO2 Group 2 unit at the source and 

all documents that demonstrate the 

truth of the statements in the certificate 

of representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such 

documents are superseded because of 

the submission of a new certificate of 

representation under § 97.716 changing 

the designated representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the TR SO2 Group 2 

Trading Program, including any 

monitoring plans and monitoring 

system certification and recertification 

applications. 

(2) The designated representative of a 

TR SO2 Group 2 source and each TR 

SO2 Group 2 unit at the source shall 

make all submissions required under 

the TR SO2 Group 2 Trading Program, 

including any submissions required for 

compliance with the TR SO2 Group 2 

assurance provisions. This requirement 

does not change, create an exemption 

from, or otherwise affect the responsible 

official submission requirements under 

a title V operating permit program in 

parts 70 and 71 of this chapter. 

(f) Liability. (1) Any provision of the 

TR SO2 Group 2 Trading Program that 

applies to a TR SO2 Group 2 source or 

the designated representative of a TR 

SO2 Group 2 source shall also apply to 

the owners and operators of such source 

and of the TR SO2 Group 2 units at the 

source. 

(2) Any provision of the TR SO2

Group 2 Trading Program that applies to 

a TR SO2 Group 2 unit or the designated 

representative of a TR SO2 Group 2 unit 

shall also apply to the owners and 

operators of such unit. 

(g) Effect on other authorities. No 

provision of the TR SO2 Group 2 

Trading Program or exemption under 

§ 97.705 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of a TR SO2 Group 2 

source or TR SO2 Group 2 unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.707 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 2 Trading Program, to begin on 

the occurrence of an act or event shall 

begin on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 2 Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

SO2 Group 2 Trading Program, falls on 

a weekend or a State or Federal holiday, 

the time period shall be extended to the 

next business day. 

§ 97.708 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR SO2 Group 2 Trading Program 

are set forth in part 78 of this chapter. 

§ 97.709 [Reserved] 

§ 97.710 State SO2 Group 2 trading 

budgets, new-unit set-asides, and variability 

limits. 

(a) The State SO2 Group 2 trading 

budgets and new-unit set-asides for 

allocations of TR SO2 Group 2 

allowances for the control periods in 

2012 and thereafter are as follows: 

State 

SO2 group 2 

trading budget 

(tons) * 

New-unit 

set-aside 

(tons) 

For 2012 and 

thereafter 

For 2012 and 

thereafter 

Alabama ........................................................................................................................................................... 161,871 4,856 

Connecticut ...................................................................................................................................................... 3,059 92 

Delaware .......................................................................................................................................................... 7,784 234 

District of Columbia ......................................................................................................................................... 337 10 

Florida .............................................................................................................................................................. 161,739 4,852 

Kansas ............................................................................................................................................................. 57,275 1,718 

Louisiana .......................................................................................................................................................... 90,477 2,714 

Maryland .......................................................................................................................................................... 39,665 1,190 

Massachusetts ................................................................................................................................................. 7,902 237 

Minnesota ........................................................................................................................................................ 47,101 1,413 

Nebraska .......................................................................................................................................................... 71,598 2,148 

New Jersey ...................................................................................................................................................... 11,291 339 

South Carolina ................................................................................................................................................. 116,483 3,494 

Total .......................................................................................................................................................... 776,582 23,297 

* Without variability limits. 

(b) The States’ one-year and three-year 

variability limits for the State SO2

Group 2 trading budgets for the control 

periods in 2014 and thereafter are as 

follows: 


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State 

One-year 

variability 

limits 

Three-year 

variability 

limits 

2014 and thereafter 

(tons) 

2016 and 

thereafter 

(tons) 

Alabama ........................................................................................................................................................... 16,187 9,346 

Connecticut ...................................................................................................................................................... 1,700 981 

Delaware .......................................................................................................................................................... 1,700 981 

District of Columbia ......................................................................................................................................... 1,700 981 

Florida .............................................................................................................................................................. 16,174 9,338 

Kansas ............................................................................................................................................................. 5,728 3,307 

Louisiana .......................................................................................................................................................... 9,048 5,224 

Maryland .......................................................................................................................................................... 3,967 2,290 

Massachusetts ................................................................................................................................................. 1,700 981 

Minnesota ........................................................................................................................................................ 4,710 2,719 

Nebraska .......................................................................................................................................................... 7,160 4,134 

New Jersey ...................................................................................................................................................... 1,700 981 

South Carolina ................................................................................................................................................. 11,648 6,725 

§ 97.711 Timing requirements for TR SO2

Group 2 allowance allocations. 

(a) Existing units. (1) TR SO2 Group 2 

allowances are allocated, for the control 

periods in 2012 and each year 

thereafter, as set forth in appendix A to 

this subpart. Listing a unit in such 

appendix does not constitute a 

determination that the unit is a TR SO2

Group 2 unit, and not listing a unit in 

such appendix does not constitute a 

determination that the unit is not a TR 

SO2 Group 2 unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit listed in 

appendix A to this subpart as being 

allocated TR SO2 Group 2 allowances 

does not operate, starting after 2011, 

during the control period in three 

consecutive years, such unit will not be 

allocated the TR SO2 Group 2 

allowances set forth in appendix A to 

this subpart for the unit for the control 

periods in the seventh year after the first 

such year and in each year after that 

seventh year. All TR SO2 Group 2 

allowances that would otherwise have 

been allocated to such unit will be 

allocated to the new unit set-aside for 

the respective years involved. If such 

unit resumes operation, the 

Administrator will allocate TR SO2

Group 2 allowances to the unit in 

accordance with paragraph (b) of this 

section. 

(b) New units. (1) By July 1, 2012, and 

July 1 of each year thereafter, the 

Administrator will calculate the TR SO2

Group 2 allowance allocation for each 

TR SO2 Group 2 unit, in accordance 

with § 97.712, for the control period in 

the year of the applicable calculation 

deadline under this paragraph and will 

promulgate a notice of availability of the 

results of the calculations. 

(2) For each notice of data availability 

required in paragraph (b)(1) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations are in 

accordance with § 97.712 and 

§§ 97.706(b)(2) and 97.730 through 

97.735. 

(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By September 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(c) Units that are not TR SO2 Group 

2 units. For each control period in 2012 

and thereafter, if the Administrator 

determines that TR SO2 Group 2 

allowances were allocated under 

paragraph (a) of this section for the 

control period to a recipient that is not 

actually a TR SO2 Group 2 unit under 

§ 97.704 as of January 1, 2012, or whose 

deadline for meeting monitor 

certification requirements under 

§ 97.730(b)(1) and (2) is after January 1, 

2012, or if the Administrator determines 

that TR SO2 Group 2 allowances were 

allocated under paragraph (b) of this 

section and § 97.712 for the control 

period to a recipient that is not actually 

a TR SO2 Group 2 unit under § 97.704 

as of January 1 of the control period, 

then the Administrator will notify the 

designated representative and will act in 

accordance with the following 

procedures: 

(1) Except as provided in paragraph 

(c)(2) or (3) of this section, the 

Administrator will not record such TR 

SO2 Group 2 allowances under § 97.721. 

(2) If the Administrator already 

recorded such TR SO2 Group 2 

allowances under § 97.721 and if the 

Administrator makes such 

determination before making deductions 

for the source that includes such 

recipient under § 97.724(b) for such 

control period, then the Administrator 

will deduct from the account in which 

such TR SO2 Group 2 allowances were 

recorded an amount of TR SO2 Group 2 

allowances allocated for the same or a 

prior control period equal to the amount 

of such already recorded TR SO2 Group 

2 allowances. The authorized account 

representative shall ensure that there are 

sufficient TR SO2 Group 2 allowances in 

such account for completion of the 

deduction. 

(3) If the Administrator already 

recorded such TR SO2 Group 2 

allowances under § 97.721 and if the 

Administrator makes such 

determination after making deductions 

for the source that includes such 

recipient under § 97.724(b) for such 

control period, then the Administrator 

will not make any deduction to take 

account of such already recorded TR 

SO2 Group 2 allowances. 

(4) The Administrator will transfer the 

TR SO2 Group 2 allowances that are not 

recorded, or that are deducted, in 

accordance with paragraphs (c)(1) and 

(2) of this section to the new unit setaside, for the State in which such 

recipient is located, for the control 

period in the year of such transfer if the 

notice required in paragraph (b)(1) of 

this section for the control period in that 

year has not been promulgated or, such 

notice has been promulgated, in the 

next year. 


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§ 97.712 TR SO2 Group 2 allowance 

allocations for new units. 

(a) For each control period in 2012 

and thereafter, the Administrator will 

allocate, in accordance with the 

following procedures, TR SO2 Group 2 

allowances to TR SO2 Group 2 units in 

a State that are not listed in appendix 

A to this subpart, to TR SO2 Group 2 

units that are so listed and whose 

allocation of SO2 Group 2 allowances 

for such control period is covered by 

§ 97.711(c)(1) or (2), and to TR SO2

Group 2 units that are so listed and, 

pursuant to § 97.711(a)(2), are not 

allocated TR SO2 Group 2 allowances 

for such control period but that operate 

during the immediately preceding 

control period: 

(1) The Administrator will establish a 

separate new unit set-aside for each 

State for each control period in a given 

year. Each new unit set-aside will be 

allocated TR SO2 Group 2 allowances in 

an amount equal to the applicable 

amount of tons of SO2 emissions as set 

forth in § 97.710(a). Each new unit setaside will be allocated additional TR 

SO2 Group 2 allowances in accordance 

with § 97.711(a)(2) and (c)(4). 

(2) The designated representative of 

such TR SO2 Group 2 unit may submit 

to the Administrator a request, in a 

format prescribed by the Administrator, 

to be allocated TR SO2 Group 2 

allowances for a control period, starting 

with the later of the control period in 

2012, the first control period after the 

control period in which the TR SO2

Group 2 unit commences commercial 

operation (for a unit not listed in 

appendix A to this subpart), or the first 

control period after the control period in 

which the unit resumes operation (for a 

unit listed in appendix A of this 

subpart) and for each subsequent 

control period. 

(i) The request must be submitted on 

or before May 1 of the first control 

period for which TR SO2 Group 2 

allowances are sought and after the date 

on which the TR SO2 Group 2 unit 

commences commercial operation (for a 

unit not listed in appendix A of this 

subpart) or on which the unit resumes 

operation (for a unit listed in appendix 

A of this subpart). 

(ii) For each control period for which 

an allocation is sought, the request must 

be for TR SO2 Group 2 allowances in an 

amount equal to the unit’s total tons of 

SO2 emissions during the immediately 

preceding control period. 

(3) The Administrator will review 

each TR SO2 Group 2 allowance 

allocation request under paragraph 

(a)(2) of this section and will accept the 

request only if it meets the requirements 

of paragraph (a)(2) of this section. The 

Administrator will allocate TR SO2

Group 2 allowances for each control 

period pursuant to an accepted request 

as follows: 

(i) After May 1 of such control period, 

the Administrator will determine the 

sum of the TR SO2 Group 2 allowances 

requested in all accepted allowance 

allocation requests for such control 

period. 

(ii) If the amount of TR SO2 Group 2 

allowances in the new unit set-aside for 

such control period is greater than or 

equal to the sum under paragraph 

(a)(3)(i) of this section, then the 

Administrator will allocate the amount 

of TR SO2 Group 2 allowances requested 

to each TR SO2 Group 2 unit covered by 

an accepted allowance allocation 

request. 

(iii) If the amount of TR SO2 Group 2 

allowances in the new unit set-aside for 

such control period is less than the sum 

under paragraph (a)(3)(i) of this section, 

then the Administrator will allocate to 

each TR SO2 Group 2 unit covered by 

an accepted allowance allocation 

request the amount of the TR SO2 Group 

2 allowances requested, multiplied by 

the amount of TR SO2 Group 2 

allowances in the new unit set-aside for 

such control period, divided by the sum 

determined under paragraph (a)(3)(i) of 

this section, and rounded to the nearest 

allowance. 

(iv) The Administrator will notify, 

through the promulgation of the notices 

of data availability described in 

§ 97.711(b), each designated 

representative that submitted an 

allowance allocation request of the 

amount of TR SO2 Group 2 allowances 

(if any) allocated for such control period 

to the TR SO2 Group 2 unit covered by 

the request. 

(b) If, after completion of the 

procedures under paragraph (a)(4) of 

this section for a control period, any 

unallocated TR SO2 Group 2 allowances 

remain in the new unit set-aside under 

paragraph (a) of this section for a State 

for such control period, the 

Administrator will allocate to each TR 

SO2 Group 2 unit that is in the State, is 

listed in appendix A to this subpart, and 

continues to be allocated TR SO2 Group 

2 allowances for such control period in 

accordance with § 97.711(a)(2), an 

amount of TR SO2 Group 2 allowances 

equal to the following: The total amount 

of such remaining unallocated TR SO2

Group 2 allowances in such new unit 

set-aside, multiplied by the unit’s 

allocation under § 97.711(a) for such 

control period, divided by the 

remainder of the amount of tons in the 

applicable State SO2 Group 2 trading 

budget minus the amount of tons in 

such new unit set-aside, and rounded to 

the nearest allowance. 

§ 97.713 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.715, 

each TR SO2 Group 2 source, including 

all TR SO2 Group 2 units at the source, 

shall have one and only one designated 

representative, with regard to all matters 

under the TR SO2 Group 2 Trading 

Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR SO2 Group 2 units 

at the source and shall act in accordance 

with the certification statement in 

§ 97.716(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.716: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR SO2 Group 2 unit at the 

source in all matters pertaining to the 

TR SO2 Group 2 Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

source and each TR SO2 Group 2 unit 

at the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.715, 

each TR SO2 Group 2 source may have 

one and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR SO2

Group 2 units at the source and shall act 

in accordance with the certification 

statement in § 97.716(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.716, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 


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inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each TR SO2 Group 2 unit 

at the source shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(c) Except in this section, § 97.702, 

and §§ 97.714 through 97.718, whenever 

the term ‘‘designated representative’’ is 

used in this subpart, the term shall be 

construed to include the designated 

representative or any alternate 

designated representative. 

§ 97.714 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.718 

concerning delegation of authority to 

make submissions, each submission 

under the TR SO2 Group 2 Trading 

Program shall be made, signed, and 

certified by the designated 

representative or alternate designated 

representative for each TR SO2 Group 2 

source and TR SO2 Group 2 unit for 

which the submission is made. Each 

such submission shall include the 

following certification statement by the 

designated representative or alternate 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR SO2

Group 2 source or a TR SO2 Group 2 

unit only if the submission has been 

made, signed, and certified in 

accordance with paragraph (a) of this 

section and § 97.718. 

§ 97.715 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators. 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.716. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the TR SO2 Group 2 source 

and the TR SO2 Group 2 units at the 

source. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.716. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the TR SO2

Group 2 source and the TR SO2 Group 

2 units at the source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a TR SO2 Group 2 source or a TR SO2

Group 2 unit is not included in the list 

of owners and operators in the 

certificate of representation under 

§ 97.716, such owner or operator shall 

be deemed to be subject to and bound 

by the certificate of representation, the 

representations, actions, inactions, and 

submissions of the designated 

representative and any alternate 

designated representative of the source 

or unit, and the decisions and orders of 

the Administrator, as if the owner or 

operator were included in such list. 

(2) Within 30 days after any change in 

the owners and operators of a TR SO2

Group 2 source or a TR SO2 Group 2 

unit, including the addition of a new 

owner or operator, the designated 

representative or any alternate 

designated representative shall submit a 

revision to the certificate of 

representation under § 97.716 amending 

the list of owners and operators to 

include the change. 

§ 97.716 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR SO2 Group 

2 source, and each TR SO2 Group 2 unit 

at the source, for which the certificate 

of representation is submitted, 

including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, unit identification number 

and type, identification number and 

nameplate capacity (in MWe rounded to 

the nearest tenth) of each generator 

served by each such unit, and actual or 

projected date of commencement of 

commercial operation. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR SO2 Group 2 source and of 

each TR SO2 Group 2 unit at the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

SO2 Group 2 unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

SO2 Group 2 Trading Program on behalf 

of the owners and operators of the 

source and of each TR SO2 Group 2 unit 

at the source and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order issued to 

me by the Administrator regarding the 

source or unit.’’ 

(iii) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a TR SO2 Group 2 

unit, or where a utility or industrial 

customer purchases power from a TR 

SO2 Group 2 unit under a life-of-theunit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘designated representative’ or ‘alternate 

designated representative’, as 

applicable, and of the agreement by 

which I was selected to each owner and 

operator of the source and of each TR 

SO2 Group 2 unit at the source; and TR 

SO2 Group 2 allowances and proceeds 

of transactions involving TR SO2 Group 

2 allowances will be deemed to be held 

or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of TR SO2 Group 2 

allowances by contract, TR SO2 Group 

2 allowances and proceeds of 

transactions involving TR SO2 Group 2 


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allowances will be deemed to be held or 

distributed in accordance with the 

contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 97.717 Objections concerning 

designated representative and alternate 

designated representative. 

(a) Once a complete certificate of 

representation under § 97.716 has been 

submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 97.716 is 

received by the Administrator. 

(b) Except as provided in § 97.715(a) 

or (b), no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the TR SO2 Group 2 Trading 

Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of TR 

SO2 Group 2 allowance transfers. 

§ 97.718 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (a) or (b) of this section, the 

designated representative or alternate 

designated representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to as an 

‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.718(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.718(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.718 is terminated.’’. 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.719 [Reserved] 

§ 97.720 Establishment of Allowance 

Management System accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.716, the 

Administrator will establish a 

compliance account for the TR SO2

Group 2 source for which the certificate 

of representation was submitted, unless 

the source already has a compliance 

account. The designated representative 

and any alternate designated 

representative of the source shall be the 

authorized account representative and 

the alternate authorized account 

representative respectively of the 

compliance account. 

(b) General accounts—(1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring TR 

SO2 Group 2 allowances, by submitting 

to the Administrator a complete 

application for a general account. Such 

application shall designate one and only 

one authorized account representative 

and may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR SO2 Group 2 allowances 

held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 


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represent their ownership interest with 

respect to the TR SO2 Group 2 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR SO2 Group 2 allowances 

held in the general account. I certify that 

I have all the necessary authority to 

carry out my duties and responsibilities 

under the TR SO2 Group 2 Trading 

Program on behalf of such persons and 

that each such person shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

order or decision issued to me by the 

Administrator regarding the general 

account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to TR 

SO2 Group 2 allowances held in the 

general account in all matters pertaining 

to the TR SO2 Group 2 Trading Program, 

notwithstanding any agreement between 

the authorized account representative 

and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to TR 

SO2 Group 2 allowances held in the 

general account shall be bound by any 

order or decision issued to the 

authorized account representative or 

alternate authorized account 

representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph 

(b)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account shall be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to TR 

SO2 Group 2 allowances held in the 

general account. Each such submission 

shall include the following certification 

statement by the authorized account 

representative or any alternate 

authorized account representative: ‘‘I am 

authorized to make this submission on 

behalf of the persons having an 

ownership interest with respect to the 

TR SO2 Group 2 allowances held in the 

general account. I certify under penalty 

of law that I have personally examined, 

and am familiar with, the statements 

and information submitted in this 

document and all its attachments. Based 

on my inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(b)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR SO2 Group 2 

allowances in the general account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR SO2 Group 2 allowances in the 

general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR SO2 Group 2 allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such person shall 

be deemed to be subject to and bound 

by the application for a general account, 

the representation, actions, inactions, 

and submissions of the authorized 

account representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to SO2 Group 2 

allowances in the general account, 

including the addition of a new person, 

the authorized account representative or 

any alternate authorized account 

representative shall submit a revision to 

the application for a general account 

amending the list of persons having an 

ownership interest with respect to the 

TR SO2 Group 2 allowances in the 

general account to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. 

(i) Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 


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representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account shall affect any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative or the 

finality of any decision or order by the 

Administrator under the TR SO2 Group 

2 Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

SO2 Group 2 allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

make an electronic submission to the 

Administrator in accordance with 

paragraph (b)(5)(i) or (ii) of this section, 

the authorized account representative or 

alternate authorized account 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(B) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such natural person (referred to 

as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (b)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 

97.720(b)(5)(iv) shall be deemed to be an 

electronic submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 40 

CFR 97.720(b)(5)(iv), I agree to maintain 

an e-mail account and to notify the 

Administrator immediately of any 

change in my e-mail address unless all 

delegation of authority by me under 40 

CFR 97.720(b)(5) is terminated.’’. 

(iv) A notice of delegation submitted 

under paragraph (b)(5)(iii) of this 

section shall be effective, with regard to 

the authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

(v) Any electronic submission covered 

by the certification in paragraph 

(b)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (b)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

(6)(i) The authorized account 

representative or alternate authorized 

account representative of a general 

account may submit to the 

Administrator a request to close the 

account. Such request shall include a 

correctly submitted TR SO2 Group 2 

allowance transfer under § 97.722 for 

any TR SO2 Group 2 allowances in the 

account to one or more other Allowance 

Management System accounts. 

(ii) If a general account has no TR SO2

Group 2 allowance transfers to or from 

the account for a 12-month period or 

longer and does not contain any TR SO2

Group 2 allowances, the Administrator 

may notify the authorized account 

representative for the account that the 

account will be closed 20 business days 

after the notice is sent. The account will 

be closed after the 20-day period unless, 

before the end of the 20-day period, the 

Administrator receives a correctly 

submitted TR SO2 Group 2 allowance 

transfer under § 97.722 to the account or 

a statement submitted by the authorized 

account representative or alternate 

authorized account representative 

demonstrating to the satisfaction of the 

Administrator good cause as to why the 

account should not be closed. 

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section. 

(d) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of an Allowance 

Management System account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of TR SO2 Group 2 

allowances in the account, only if the 

submission has been made, signed, and 

certified in accordance with §§ 97.714(a) 

and 97.718 or paragraphs (b)(2)(ii) and 

(b)(5) of this section. 

§ 97.721 Recordation of TR SO2 Group 2 

allowance allocations. 

(a) By September 1, 2011, the 

Administrator will record in each TR 

SO2 Group 2 source’s compliance 

account the TR SO2 Group 2 allowances 

allocated for the TR SO2 Group 2 units 

at the source in accordance with 

§§ 97.711(a) for the control periods in 

2012, 2013, and 2014. 

(b) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

record in each TR SO2 Group 2 source’s 

compliance account the TR SO2 Group 

2 allowances allocated for the TR SO2

Group 2 units at the source in 

accordance with § 97.711(a) for the 

control period in the third year after the 

year of the applicable recordation 

deadline under this paragraph. 

(c) By September 1, 2012 and 

September 1 of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 2 source’s compliance 

account the TR SO2 Group 2 allowances 

allocated for the TR SO2 Group 2 units 

at the source in accordance with 

§ 97.712 for the control period in the 

year of the applicable recordation 

deadline under this paragraph. 

(d) When recording the allocation of 

TR SO2 Group 2 allowances for a TR 

SO2 Group 2 unit in a compliance 


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account, the Administrator will assign 

each TR SO2 Group 2 allowance a 

unique identification number that will 

include digits identifying the year of the 

control period for which the TR SO2

Group 2 allowance is allocated. 

§ 97.722 Submission of TR SO2 Group 2 

allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR SO2 Group 2 allowance transfer shall 

submit the transfer to the Administrator. 

(b) A TR SO2 Group 2 allowance 

transfer shall be correctly submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR SO2

Group 2 allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR SO2 Group 2 

allowance identified by serial number in 

the transfer. 

§ 97.723 Recordation of TR SO2 Group 2 

allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR SO2 Group 2 

allowance transfer, the Administrator 

will record a TR SO2 Group 2 allowance 

transfer by moving each TR SO2 Group 

2 allowance from the transferor account 

to the transferee account as specified by 

the request, provided that the transfer is 

correctly submitted under § 97.722. 

(b)(1) A TR SO2 Group 2 allowance 

transfer that is submitted for recordation 

after the allowance transfer deadline for 

a control period and that includes any 

TR SO2 Group 2 allowances allocated 

for any control period before such 

allowance transfer deadline will not be 

recorded until after the Administrator 

completes the deductions under 

§ 97.724 for the control period 

immediately before such allowance 

transfer deadline. 

(2) A TR SO2 Group 2 allowance 

transfer that is submitted for recordation 

after the deadline for holding TR SO2

Group 2 allowances described in 

§ 97.725(b)(5) and that includes any TR 

SO2 Group 2 allowances allocated for a 

control period before the year of such 

deadline will not be recorded until after 

the Administrator completes the 

deductions under § 97.725 for the 

control period immediately before the 

year of such deadline. 

(c) Where a TR SO2 Group 2 

allowance transfer is not correctly 

submitted under § 97.722, the 

Administrator will not record such 

transfer. 

(d) Within 5 business days of 

recordation of a TR SO2 Group 2 

allowance transfer under paragraphs (a) 

and (b) of the section, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR SO2 Group 2 allowance transfer 

that is not correctly submitted under 

§ 97.722, the Administrator will notify 

the authorized account representatives 

of both accounts subject to the transfer 

of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.724 Compliance with TR SO2 Group 2 

emissions limitation. 

(a) Availability for deduction for 

compliance. TR SO2 Group 2 allowances 

are available to be deducted for 

compliance with a source’s TR SO2

Group 2 emissions limitation for a 

control period in a given year only if the 

TR SO2 Group 2 allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in the source’s 

compliance account as of the allowance 

transfer deadline for such control 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 97.723, of TR SO2 Group 2 allowance 

transfers submitted by the allowance 

transfer deadline for a control period, 

the Administrator will deduct from the 

compliance account TR SO2 Group 2 

allowances available under paragraph 

(a) of this section in order to determine 

whether the source meets the TR SO2

Group 2 emissions limitation for such 

control period, as follows: 

(1) Until the amount of TR SO2 Group 

2 allowances deducted equals the 

number of tons of total SO2 emissions 

from all TR SO2 Group 2 units at the 

source for such control period; or 

(2) If there are insufficient TR SO2

Group 2 allowances to complete the 

deductions in paragraph (b)(1) of this 

section, until no more TR SO2 Group 2 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(c)(1) Identification of TR SO2 Group 

2 allowances by serial number. The 

authorized account representative for a 

source’s compliance account may 

request that specific TR SO2 Group 2 

allowances, identified by serial number, 

in the compliance account be deducted 

for emissions or excess emissions for a 

control period in accordance with 

paragraph (b) or (d) of this section. In 

order to be complete, such request shall 

be submitted to the Administrator by 

the allowance transfer deadline for such 

control period and include, in a format 

prescribed by the Administrator, the 

identification of the TR SO2 Group 2 

source and the appropriate serial 

numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR SO2

Group 2 allowances under paragraph (b) 

or (d) of this section from the source’s 

compliance account in accordance with 

a complete request under paragraph 

(c)(1) of this section or, in the absence 

of such request or in the case of 

identification of an insufficient amount 

of TR SO2 Group 2 allowances in such 

request, on a first-in, first-out (FIFO) 

accounting basis in the following order: 

(i) Any TR SO2 Group 2 allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR SO2 Group 2 allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a year in 

which the TR SO2 Group 2 source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account an amount of TR SO2 Group 2 

allowances, allocated for the control 

period in the immediately following 

year, equal to two times the number of 

tons of the source’s excess emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.725 Compliance with TR SO2 Group 2 

assurance provisions. 

(a) Availability for deduction. TR SO2

Group 2 allowances are available to be 

deducted for compliance with the TR 

SO2 Group 2 assurance provisions for a 

control period in a given year by an 

owner of one or more TR SO2 Group 2 

units in a State only if the TR SO2

Group 2 allowances: 

(1) Were allocated for the control 

period in the year or a prior year; and 

(2) Are held in a compliance account, 

designated by the owner in accordance 

with paragraph (b)(4)(ii) of this section, 


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of one of the owner’s TR SO2 Group 2 

sources in the State as of the deadline 

established in paragraph (b)(5) of this 

section. 

(b) Deductions for compliance. The 

Administrator will deduct TR SO2

Group 2 allowances available under 

paragraph (a) of this section for 

compliance with the TR SO2 Group 2 

assurance provisions for a State for a 

control period in a given year in 

accordance with the following 

procedures: 

(1) By June 1, 2015 and June 1 of each 

year thereafter, the Administrator will: 

(i) Calculate, separately for each State, 

the total amount of SO2 emissions from 

all TR SO2 Group 2 units in the State 

during the control period in the year 

before the year of this calculation 

deadline and the amount, if any, by 

which such total amount of NOX

emissions exceeds the State assurance 

level as described in § 97.706(c)(2)(iii); 

and 

(ii) Promulgate a notice of availability 

of the results of the calculations 

required in paragraph (b)(1)(i) of this 

section, including separate calculations 

of the SO2 emissions for each TR SO2

Group 2 unit and of the amounts 

described in §§ 97.706(c)(2)(iii)(A) and 

(B) for each State. 

(2) The Administrator will provide an 

opportunity for submission of objections 

to the calculations referenced by each 

notice described in paragraph (b)(1) of 

this section. 

(i) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each TR 

SO2 Group 2 unit and each State for the 

control period in the year involved are 

in accordance with § 97.706(c)(2)(iii) 

and §§ 97.706(b) and 97.730 through 

97.735. 

(ii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(i) of this section. By August 1 

immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of availability of 

any adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(2)(i) of this section. 

(3) For each notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and for any State identified in 

such notice as having TR SO2 Group 2 

sources with total SO2 emissions 

exceeding the State assurance level for 

a control period, as described in 

§ 97.706(c)(2)(iii): 

(i) By August 15 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

SO2 Group 2 source in each such State 

shall submit a statement, in a format 

prescribed by the Administrator: 

(A) Listing all the owners of each TR 

SO2 Group 2 unit at the source, 

explaining how the selection of each 

owner for inclusion on the list is 

consistent with the definition of 

‘‘owner’’ in § 97.702, and listing, 

separately for each unit, the percentage 

of the legal, equitable, leasehold, or 

contractual reservation or entitlement 

for each such owner as of midnight of 

December 31 of the control period in the 

year involved; and 

(B) For each TR SO2 Group 2 unit at 

the source that operates during, but is 

allocated no TR SO2 Group 2 allowances 

for, the control period in the year 

involved, identifying whether the unit is 

a coal-fired boiler, simple combustion 

turbine, or combined cycle turbine cycle 

and providing the unit’s allowable SO2

emission rate for such control period. 

(ii) By September 15 immediately 

after the promulgation of such notice, 

the Administrator will calculate, for 

each such State and each owner of one 

or more TR SO2 Group 2 units in the 

State and for the control period in the 

year involved, each owner’s share of the 

total SO2 emissions from all TR SO2

Group 2 units in the State, each owner’s 

assurance level, and the amount (if any) 

of TR SO2 Group 2 allowances that each 

owner must hold in accordance with the 

calculation formula in § 97.706(c)(2)(i) 

and will promulgate a notice of 

availability of the results of these 

calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 

required in paragraph (b)(3)(ii) of this 

section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations for each owner 

for the control period in the year 

involved are consistent with the SO2

emissions for the relevant TR SO2 Group 

2 units as set forth in the notice required 

in paragraph (b)(2)(ii) of this section, the 

definitions of ‘‘owner’’, ‘‘owner’s 

assurance level’’, and ‘‘owner’s share’’ in 

§ 97.702, and the calculation formula in 

§ 97.706(c)(2)(i) and shall not raise any 

issues about any data used in the notice 

of data availability required in 

paragraph (b)(2)(ii) of this section. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are consistent with the 

data and provisions referenced in 

paragraph (b)(3)(iii)(A) of this section. 

By November 15 immediately after the 

promulgation of such notice, the 

Administrator will promulgate a notice 

of availability of any adjustments that 

the Administrator determines to be 

necessary and the reasons for accepting 

or rejecting any objections submitted in 

accordance with paragraph (b)(3)(iii)(A) 

of this section. 

(4) By December 1 immediately after 

the promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section: 

(i) Each owner identified, in such 

notice, as owning one or more TR SO2

Group 2 units in a State and as being 

required to hold TR SO2 Group 2 

allowances shall designate the 

compliance account of one of the 

sources at which such unit or units are 

located to hold such required TR SO2

Group 2 allowances; 

(ii) The authorized account 

representative for the compliance 

account designated under paragraph 

(b)(4)(i) of this section shall submit to 

the Administrator a statement, in a 

format prescribed by the Administrator, 

making this designation. 

(5)(i) As of midnight of December 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(3)(iii)(B) of this section, 

each owner described in paragraph 

(b)(4)(i) of this section shall hold in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section the total amount 

of TR SO2 Group 2 allowances, available 

for deduction under paragraph (a) of 

this section, equal to the amount the 

owner is required to hold as calculated 

by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(5)(i) of this section, if December 15 

is not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(6) After December 15 (or the date 

described in paragraph (b)(5)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(3)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.723, of TR SO2 Group 2 allowance 

transfers submitted by midnight of such 

date, the Administrator will deduct 

from each compliance account 

designated in accordance with 

paragraph (b)(4)(ii) of this section, TR 

SO2 Group 2 allowances available under 

paragraph (a) of this section, as follows: 

(i) Until the amount of TR SO2 Group 

2 allowances deducted equals the 


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amount that the owner designating the 

compliance account is required to hold 

as calculated by the Administrator and 

referenced in the notice required in 

paragraph (b)(3)(iii)(B) of this section; or 

(ii) If there are insufficient TR SO2

Group 2 allowances to complete the 

deductions in paragraph (b)(6)(i) of this 

section, until no more TR SO2 Group 2 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(7) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notices of data availability required 

in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) 

of this section respectively for a control 

period, of any data used in making the 

calculations referenced in such notice, 

the amount of TR SO2 Group 2 

allowances that each owner is required 

to hold in accordance with 

§ 97.706(c)(2)(i) for the control period in 

the year involved shall continue to be 

such amount as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(3)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR SO2 Group 2 allowances that 

owners are required to hold in 

accordance with the calculation formula 

in § 97.706(c)(2)(i) for the control period 

in the year involved with regard to the 

State involved, provided that— 

(A) With regard to such litigation 

involving such notice required in 

paragraph (b)(2)(ii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(ii) of this section; and 

(B) With regard to such litigation 

involving such notice required in 

paragraph (b)(3)(iii) of this section, such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(3)(iii) of this section. 

(ii) If any such data are revised by the 

owners and operators of a source whose 

designated representative submitted 

such data under paragraph (b)(3)(i) of 

this section, as a result of a decision in 

or settlement of litigation concerning 

such submission, then the 

Administrator will use the data as so 

revised to recalculate the amounts of TR 

SO2 Group 2 allowances that owners are 

required to hold in accordance with the 

calculation formula in § 97.706(c)(2)(i) 

for the control period in the year 

involved with regard to the State 

involved, provided that such litigation 

was initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(3)(iii)(B) of this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(7)(i) and (b)(7)(ii) of this 

section, the amount of TR SO2 Group 2 

allowances that an owner is required to 

hold for the control period in the year 

involved with regard to the State 

involved— 

(A) Where the amount of TR SO2

Group 2 allowances that an owner is 

required to hold increases as a result of 

the use of all such revised data, the 

Administrator will establish a new, 

reasonable deadline on which the owner 

shall hold the additional amount of TR 

SO2 Group 2 allowances in the 

compliance account designated by the 

owner in accordance with paragraph 

(b)(4)(ii) of this section. The owner’s 

failure to hold such additional amount, 

as required, before the new deadline 

shall not be a violation of the Clean Air 

Act. The owner’s failure to hold such 

additional amount, as required, as of the 

new deadline shall be a violation of the 

Clean Air Act. Each TR SO2 Group 2 

allowance that the owner fails to hold 

as required as of the new deadline, and 

each day in the control period in the 

year involved, shall be a separate 

violation of the Clean Air Act. After 

such deadline, the Administrator will 

make the appropriate deductions from 

the compliance account. 

(B) For an owner for which the 

amount of TR SO2 Group 2 allowances 

required to be held decreases as a result 

of the use of all such revised data, the 

Administrator will record, in the 

compliance account that the owner 

designated in accordance with 

paragraph (b)(4)(ii) of this section, an 

amount of TR SO2 Group 2 allowances 

equal to the amount of the decrease to 

the extent such amount was previously 

deducted from the compliance account 

under paragraph (b)(6) of this section 

(and has not already been restored to the 

compliance account) for the control 

period in the year involved. 

(C) Each TR SO2 Group 2 allowance 

held and deducted under paragraph 

(b)(7)(iii)(A) of this section, or recorded 

under paragraph (b)(7)(iii)(B) of this 

section, as a result of recalculation of 

requirements under the TR SO2 Group 

2 assurance provisions for a control 

period in a given year must be a TR SO2

Group 2 allowance allocated for a 

control period in the same or a prior 

year. 

(c)(1) Identification of TR SO2 Group 

2 allowances by serial number. The 

authorized account representative for 

each source’s compliance account 

designated in accordance with 

paragraph (b)(4)(ii) of this section may 

request that specific TR SO2 Group 2 

allowances, identified by serial number, 

in the compliance account be deducted 

in accordance with paragraph (b)(6) or 

(7) of this section. In order to be 

complete, such request shall be 

submitted to the Administrator by the 

allowance-holding deadline described 

in paragraph (b)(5) of this section and 

include, in a format prescribed by the 

Administrator, the identification of the 

compliance account and the appropriate 

serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR SO2

Group 2 allowances under paragraphs 

(b)(6) and (7) of this section from each 

source’s compliance account designated 

under paragraph (b)(4)(ii) of this section 

in accordance with a complete request 

under paragraph (c)(1) of this section or, 

in the absence of such request or in the 

case of identification of an insufficient 

amount of TR SO2 Group 2 allowances 

in such request, on a first-in, first-out 

(FIFO) accounting basis in the following 

order: 

(i) Any TR SO2 Group 2 allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR SO2 Group 2 allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) of this section. 

§ 97.726 Banking. 

(a) A TR SO2 Group 2 allowance may 

be banked for future use or transfer in 

a compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any TR SO2 Group 2 allowance 

that is held in a compliance account or 

a general account will remain in such 


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account unless and until the TR SO2

Group 2 allowance is deducted or 

transferred under § 97.711(c), § 97.723, 

§ 97.724, § 97.725, 97.727, 97.728, 

97.742, or 97.743. 

§ 97.727 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.728 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR SO2

Group 2 Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

SO2 Group 2 allowances from or transfer 

TR SO2 Group 2 allowances to a 

source’s compliance account based on 

the information in a submission, as 

adjusted under paragraph (a)(1) of this 

section, and record such deductions and 

transfers. 

§ 97.729 [Reserved] 

§ 97.730 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR SO2 Group 2 

unit, shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and subparts F and G of part 75 of this 

chapter. For purposes of applying such 

requirements, the definitions in § 97.702 

and in § 72.2 of this chapter shall apply, 

the terms ‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘TR SO2

Group 2 unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively as defined in 

§ 97.702, and the term ‘‘newly affected 

unit’’ shall be deemed to mean ‘‘newly 

affected TR SO2 Group 2 unit’’. The 

owner or operator of a unit that is not 

a TR SO2 Group 2 unit but that is 

monitored under § 75.16(b)(2) of this 

chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a TR SO2

Group 2 unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR SO2 Group 

2 unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring SO2 mass emissions and 

individual unit heat input (including all 

systems required to monitor SO2

concentration, stack gas moisture 

content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as 

applicable, in accordance with §§ 75.11 

and 75.16 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.731 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates. The owner or 

operator shall record, report, and 

quality-assure the data from the 

monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

SO2 Group 2 unit that commences 

commercial operation before July 1, 

2011, by January 1, 2012. 

(2) For the owner or operator of a TR 

SO2 Group 2 unit that commences 

commercial operation on or after July 1, 

2011, by the later of the following dates: 

(i) January 1, 2012; or 

(ii) 180 calendar days, whichever 

occurs first, after the date on which the 

unit commences commercial operation. 

(3) For the owner or operator of a TR 

SO2 Group 2 unit for which 

construction of a new stack or flue or 

installation of add-on SO2 emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1) or (2) of this section, by 90 unit 

operating days or 180 calendar days, 

whichever occurs first, after the date on 

which emissions first exit to the 

atmosphere through the new stack or 

flue or add-on SO2 emissions controls. 

(4) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a unit for 

which a TR opt-in application is 

submitted and not withdrawn and is not 

yet approved or disapproved, by the 

date specified in § 97.741(c). 

(5) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a TR SO2

Group 2 opt-in unit, by the date on 

which the TR SO2 Group 2 opt-in unit 

enters the TR SO2 Group 2 Trading 

Program as provided in § 97.741(h). 

(c) Reporting data. The owner or 

operator of a TR SO2 Group 2 unit that 

does not meet the applicable 

compliance date set forth in paragraph 

(b) of this section for any monitoring 

system under paragraph (a)(1) of this 

section shall, for each such monitoring 

system, determine, record, and report 

maximum potential (or, as appropriate, 

minimum potential) values for SO2

concentration, stack gas flow rate, stack 

gas moisture content, fuel flow rate, and 

any other parameters required to 

determine SO2 mass emissions and heat 

input in accordance with § 75.31(b)(2) 

or (c)(3) of this chapter or section 2.4 of 

appendix D to part 75 of this chapter, as 

applicable. 

(d) Prohibitions. (1) No owner or 

operator of a TR SO2 Group 2 unit shall 

use any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this subpart without having obtained 

prior written approval in accordance 

with § 97.735. 

(2) No owner or operator of a TR SO2

Group 2 unit shall operate the unit so 

as to discharge, or allow to be 

discharged, SO2 emissions to the 

atmosphere without accounting for all 

such emissions in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter. 

(3) No owner or operator of a TR SO2

Group 2 unit shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording SO2 mass emissions 

discharged into the atmosphere or heat 

input, except for periods of 

recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the applicable provisions of this 

subpart and part 75 of this chapter. 

(4) No owner or operator of a TR SO2

Group 2 unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.705 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 


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pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.731(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR SO2 Group 2 unit is 

subject to the applicable provisions of 

§ 75.4(d) of this chapter concerning 

units in long-term cold storage. 

§ 97.731 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR SO2

Group 2 unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 97.730(a)(1) if the following conditions 

are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B and D to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.730(a)(1) exempt 

from initial certification requirements 

under paragraph (a) of this section. 

(c) [Reserved] 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR SO2 Group 2 unit shall comply 

with the following initial certification 

and recertification procedures, for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendix D to part 75 of this 

chapter) under § 97.730(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.730(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.730(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.730(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record SO2 mass emissions or heat input 

rate or to meet the quality-assurance and 

quality-control requirements of § 75.21 

of this chapter or appendix B to part 75 

of this chapter, the owner or operator 

shall recertify the monitoring system in 

accordance with § 75.20(b) of this 

chapter. Furthermore, whenever the 

owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit’s operation 

that may significantly change the stack 

flow or concentration profile, the owner 

or operator shall recertify each 

continuous emission monitoring system 

whose accuracy is potentially affected 

by the change, in accordance with 

§ 75.20(b) of this chapter. Examples of 

changes to a continuous emission 

monitoring system that require 

recertification include: Replacement of 

the analyzer, complete replacement of 

an existing continuous emission 

monitoring system, or change in 

location or orientation of the sampling 

probe or site. Any fuel flowmeter system 

under § 97.730(a)(1) is subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.730(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 

procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word ‘‘certified’’ 

is replaced by the word ‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.733. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR SO2 Group 2 Trading Program for 

a period not to exceed 120 days after 

receipt by the Administrator of the 

complete certification application for 

the monitoring system under paragraph 

(d)(3)(ii) of this section. Data measured 

and recorded by the provisionally 

certified monitoring system, in 

accordance with the requirements of 

part 75 of this chapter, will be 

considered valid quality-assured data 

(retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR SO2 Group 2 Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. The 120-day 

review period specified in paragraph 


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(d)(3) of this section shall not begin 

before receipt of a complete certification 

application. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.732(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved SO2 pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

SO2 and the maximum potential flow 

rate, as defined in sections 2.1.1.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(2) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(3) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.732 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or appendix D to part 75 of 

this chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.731 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

Administrator or any permitting 

authority. By issuing the notice of 

disapproval, the Administrator revokes 

prospectively the certification status of 

the monitoring system. The data 

measured and recorded by the 

monitoring system shall not be 

considered valid quality-assured data 

from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 97.731 for each 

disapproved monitoring system. 

§ 97.733 Notifications concerning 

monitoring. 

The designated representative of a TR 

SO2 Group 2 unit shall submit written 

notice to the Administrator in 

accordance with § 75.61 of this chapter. 

§ 97.734 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in this section, the 

applicable recordkeeping and reporting 

requirements in subparts F and G of part 

75 of this chapter, and the requirements 

of § 97.714(a). 

(b) Monitoring plans. The owner or 

operator of a TR SO2 Group 2 unit shall 

comply with requirements of § 75.62 of 

this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.731, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) The designated representative 

shall report the SO2 mass emissions data 

and heat input data for the TR SO2

Group 2 unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering 

January 1, 2012 through March 31, 2012; 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.730(b), unless 

that quarter is the third or fourth quarter 

of 2011, in which case reporting shall 


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commence in the quarter covering 

January 1, 2012 through March 31, 2012; 

(iii) Notwithstanding paragraphs 

(d)(1)(i) and (ii) of this section, for a unit 

for which a TR opt-in application is 

submitted and not withdrawn and is not 

yet approved or disapproved, the 

calendar quarter corresponding to the 

date specified in § 97.741(c); and 

(iv) Notwithstanding paragraphs 

(d)(1)(i) and (ii) of this section, for a TR 

SO2 Group 2 opt-in unit, the calendar 

quarter corresponding to the date on 

which the TR SO2 Group 1 opt-in unit 

enters the TR SO2 Group 2 Trading 

Program as provided in § 97.71(h). 

(2) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.64 of this chapter. 

(3) For TR SO2 Group 2 units that are 

also subject to the Acid Rain Program, 

TR NOX Annual Trading Program, or TR 

NOX Ozone Season Trading Program, 

quarterly reports shall include the 

applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the SO2 mass emission data, 

heat input data, and other information 

required by this subpart. 

(4) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(ii) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(2) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on SO2

emission controls and for all hours 

where SO2 data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate SO2

emissions. 

§ 97.735 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR SO2 Group 2 unit may submit a 

petition under § 75.66 of this chapter to 

the Administrator, requesting approval 

to apply an alternative to any 

requirement of §§ 97.730 through 97.734 

or paragraph (5)(i) or (ii) of the 

definition of ‘‘owner’s share’’ in 

§ 97.702. 

(b) A petition submitted under 

paragraph (a) of this section shall 

include sufficient information for the 

evaluation of the petition, including, at 

a minimum, the following information: 

(i) Identification of each unit and 

source covered by the petition; 

(ii) A detailed explanation of why the 

proposed alternative is being suggested 

in lieu of the requirement; 

(iii) A description and diagram of any 

equipment and procedures used in the 

proposed alternative; 

(iv) A demonstration that the 

proposed alternative is consistent with 

the purposes of the requirement for 

which the alternative is proposed and 

with the purposes of this subpart and 

part 75 of this chapter and that any 

adverse effect of approving the 

alternative will be de minimis; and 

(v) Any other relevant information 

that the Administrator may require. 

(c) Use of an alternative to any 

requirement referenced in paragraph (a) 

of this section is in accordance with this 

subpart only to the extent that the 

petition is approved in writing by the 

Administrator and that such use is in 

accordance with such approval. 

§ 97.740 General requirements for TR SO2

Group 2 opt-in units. 

(a) A TR SO2 Group 2 opt-in unit must 

be a unit that: 

(1) Is located in a State; 

(2) Is not a TR SO2 Group 2 unit under 

§ 97.704; 

(3) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; and 

(4) Vents all of its emissions to a stack 

and can meet the monitoring, 

recordkeeping, and reporting 

requirements of this subpart. 

(b) A TR SO2 Group 2 opt-in unit shall 

be deemed to be a TR SO2 Group 2 unit 

for purposes of applying this subpart, 

except for §§ 97.705, 97.711, and 97.712. 

(c) Solely for purposes of applying the 

requirements of §§ 97.713 through 

97.718 and §§ 97.730 through 97.735, a 

unit for which a TR opt-in application 

is submitted and not withdrawn and is 

not yet approved or disapproved under 

§ 97.742 shall be deemed to be a TR SO2

Group 2 unit. 

(d) Any TR SO2 Group 2 opt-in unit, 

and any unit for which a TR opt-in 

application is submitted and not 

withdrawn and is not yet approved or 

disapproved under § 97.742, located at 

the same source as one or more TR SO2

Group 2 units shall have the same 

designated representative and alternate 

designated representative as such TR 

SO2 Group 2 units. 

§ 97.741 Opt-in process. 

A unit meeting the requirements for a 

TR SO2 Group 2 opt-in unit in 

§ 97.740(a) may become a TR SO2 Group 

2 opt-in unit only if, in accordance with 

this section, the designated 

representative of the unit submits a 

complete TR opt-in application for the 

unit and the Administrator approves the 

application. 

(a) Applying to opt-in. The designated 

representative of the unit may submit a 

complete TR opt-in application for the 

unit at any time, except as provided 

under § 97.742(e). A complete TR opt-in 

application shall include the following 

elements in a format prescribed by the 

Administrator: 

(1) Identification of the unit and the 

source where the unit is located, 


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including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, and unit identification 

number and type; 

(2) A certification that the unit: 

(i) Is not a TR SO2 Group 2 unit under 

§ 97.704; 

(ii) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(iii) Vents all of its emissions to a 

stack; and 

(iv) Has documented heat input 

(greater than 0 mmBtu) for more than 

876 hours during the 6 months 

immediately preceding submission of 

the TR opt-in application; 

(3) A monitoring plan in accordance 

with §§ 97.730 through 97.735; 

(4) A statement that the unit, if 

approved to become a TR SO2 Group 2 

unit under paragraph (g) of this section, 

may withdraw from the TR SO2 Group 

2 Trading Program only in accordance 

with § 97.742; 

(5) A statement that the unit, if 

approved to become a TR SO2 Group 2 

unit under paragraph (g) of this section, 

is subject to, and the owners and 

operators of the unit must comply with, 

the requirements of § 97.743; 

(6) A complete certificate of 

representation under § 97.716 consistent 

with § 97.740, if no designated 

representative has been previously 

designated for the source that includes 

the unit; and 

(7) The signature of the designated 

representative and the date signed. 

(b) Interim review of monitoring plan. 

The Administrator will determine, on 

an interim basis, the sufficiency of the 

monitoring plan submitted under 

paragraph (a)(3) of this section. The 

monitoring plan is sufficient, for 

purposes of interim review, if the plan 

appears to contain information 

demonstrating that the SO2 emission 

rate and heat input of the unit and all 

other applicable parameters are 

monitored and reported in accordance 

with §§ 97.730 through 97.735. A 

determination of sufficiency shall not be 

construed as acceptance or approval of 

the monitoring plan. 

(c) Monitoring and reporting. (1)(i) If 

the Administrator determines that the 

monitoring plan is sufficient under 

paragraph (b) of this section, the owner 

or operator of the unit shall monitor and 

report the SO2 emission rate and the 

heat input of the unit and all other 

applicable parameters, in accordance 

with §§ 97.730 through 97.735, starting 

on the date of certification of the 

necessary monitoring systems under 

§§ 97.730 through 97.735 and 

continuing until the TR opt-in 

application submitted under paragraph 

(a) of this section is disapproved under 

this section or, if such TR opt-in 

application is approved, the date and 

time when the unit is withdrawn from 

the TR SO2 Group 2 Trading Program in 

accordance with § 97.742. 

(ii) The monitoring and reporting 

under paragraph (c)(1)(i) of this section 

shall cover the entire control period 

immediately before the date on which 

the unit enters the TR SO2 Group 2 

Trading Program under paragraph (h) of 

this section, during which period 

monitoring system availability must not 

be less than 98 percent under §§ 97.730 

through 97.735 and the unit must be in 

full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(2) To the extent the SO2 emission 

rate and the heat input of the unit are 

monitored and reported in accordance 

with §§ 97.730 through 97.735 for one or 

more entire control periods, in addition 

to the control period under paragraph 

(c)(1)(ii) of this section, during which 

control periods monitoring system 

availability is not less than 98 percent 

under §§ 97.730 through 97.735 and the 

unit is in full compliance with any 

applicable State or Federal emissions or 

emissions-related requirements and 

which control periods begin not more 

than 3 years before the unit enters the 

TR SO2 Group 2 Trading Program under 

paragraph (h) of this section, such 

information shall be used as provided in 

paragraphs (e) and (f) of this section. 

(d) Statement on compliance. After 

submitting to the Administrator all 

quarterly reports required for the unit 

under paragraph (c) of this section, the 

designated representative shall submit, 

in a format prescribed by the 

Administrator, to the Administrator a 

statement that, for the years covered by 

such quarterly reports, the unit was in 

full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(e) Baseline heat input. The unit’s 

baseline heat input shall equal: 

(1) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for only one entire control period, in 

accordance with paragraph (c) of this 

section, the unit’s total heat input (in 

mmBtu) for such control period; or 

(2) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, the average of the amounts of 

the unit’s total heat input (in mmBtu) 

for such control periods. 

(f) Baseline SO2 emission rate. The 

unit’s baseline SO2 emission rate shall 

equal: 

(1) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for only one entire control period, in 

accordance with paragraph (c) of this 

section, the unit’s SO2 emission rate (in 

lb/mmBtu) for such control period; 

(2) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit does not have addon SO2 emission controls during any 

such control periods, the average of the 

amounts of the unit’s SO2 emission rate 

(in lb/mmBtu) for such control periods; 

or 

(3) If the unit’s SO2 emission rate and 

heat input are monitored and reported 

for more than one entire control period, 

in accordance with paragraph (c) of this 

section, and the unit has add-on SO2

emission controls during any such 

control periods, the average of the 

amounts of the unit’s SO2 emission rate 

(in lb/mmBtu) for such control periods 

during which the unit has add-on SO2

emission controls. 

(g) Review of TR opt-in application. 

(1) After the designated representative 

submits the complete TR opt-in 

application, quarterly reports, and 

statement required in paragraphs (a), (c), 

and (d) of this section and if the 

Administrator determines that the 

designated representative shows that the 

unit meets the requirements for a TR 

SO2 Group 2 opt-in unit in § 97.640, the 

element certified in paragraph (a)(2)(iv) 

of this section, and the monitoring and 

reporting requirements of paragraph (c) 

of this section, the Administrator will 

issue a written approval of the TR optin application for the unit. The written 

approval will state the unit’s baseline 

heat input and baseline SO2 emission 

rate. The Administrator will thereafter 

establish a compliance account for the 

source that includes the unit unless the 

source already has a compliance 

account. 

(2) Notwithstanding paragraphs (a) 

through (f) of this section, if, at any time 

before the TR opt-in application is 

approved under paragraph (g)(1) of this 

section, the Administrator determines 

that the unit cannot meet the 

requirements for a TR SO2 Group 2 optin unit in § 97.740, the element certified 

in paragraph (a)(2)(iv) of this section, or 

the monitoring and reporting 

requirements in paragraph (c) of this 

section, the Administrator will issue a 

written disapproval of the TR opt-in 

application for the unit. 

(h) Date of entry into TR SO2 Group 

2 Trading Program. A unit for which a 


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TR opt-in application is approved under 

paragraph (g)(1) of this section shall 

become a TR SO2 Group 2 opt-in unit, 

and a TR SO2 Group 2 unit, effective as 

of the later of January 1, 2012 or January 

1 of the first control period during 

which such approval is issued. 

§ 97.742 Withdrawal of TR SO2 Group 2 

opt-in unit from TR SO2 Group 2 Trading 

Program. 

A TR SO2 Group 2 opt-in unit may 

withdraw from the TR SO2 Group 2 

Trading Program only if, in accordance 

with this section, the designated 

representative of the unit submits a 

request to withdraw the unit and the 

Administrator issues a written approval 

of the request. 

(a) Requesting withdrawal. In order to 

withdraw the TR SO2 Group 2 opt-in 

unit from the TR SO2 Group 2 Trading 

Program, the designated representative 

of the unit shall submit to the 

Administrator a request to withdraw the 

unit effective as of midnight of 

December 31 of a specified calendar 

year, which date must be at least 4 years 

after December 31 of the year of the 

unit’s entry into the TR SO2 Group 2 

Trading Program under § 97.741(h). The 

request shall be in a format prescribed 

by the Administrator and shall be 

submitted no later than 90 days before 

the requested effective date of 

withdrawal. 

(b) Conditions for withdrawal. Before 

a TR SO2 Group 2 opt-in unit covered 

by the request to withdraw may 

withdraw from the TR SO2 Group 2 

Trading Program, the following 

conditions must be met: 

(1) For the control period ending on 

the date on which the withdrawal is to 

be effective, the source that includes the 

TR SO2 Group 2 opt-in unit must meet 

the requirement to hold TR SO2 Group 

2 allowances under §§ 97.724 and 

97.725 and cannot have any excess 

emissions. 

(2) After the requirement under 

paragraph (b)(1) of this section is met, 

the Administrator will deduct from the 

compliance account of the source that 

includes the TR SO2 Group 2 opt-in unit 

TR SO2 Group 2 allowances equal in 

amount to and allocated for the same or 

a prior control period as any TR SO2

Group 2 allowances allocated to the TR 

SO2 Group 2 opt-in unit under § 97.744 

for any control period after the date on 

which the withdrawal is to be effective. 

If there are no other TR SO2 Group 2 

units at the source, the Administrator 

will close the compliance account, and 

the owners and operators of the TR SO2

Group 2 opt-in unit may submit a TR 

SO2 Group 2 allowance transfer for any 

remaining TR SO2 Group 2 allowances 

to another Allowance Management 

System account in accordance with 

§§ 97.722 and 97.723. 

(c) Approving withdrawal. (1) After 

the requirements for withdrawal under 

paragraphs (a) and (b) of this section are 

met (including deduction of the full 

amount of TR SO2 Group 2 allowances 

required), the Administrator will issue a 

written approval of the request to 

withdraw, which will become effective 

as of midnight on December 31 of the 

calendar year for which the withdrawal 

was requested. The unit covered by the 

request shall continue to be a TR SO2

Group 2 opt-in unit until the effective 

date of the withdrawal and shall comply 

with all requirements under the TR SO2

Group 2 Trading Program concerning 

any control periods for which the unit 

is a TR SO2 Group 2 opt-in unit, even 

if such requirements arise or must be 

complied with after the withdrawal 

takes effect. 

(2) If the requirements for withdrawal 

under paragraphs (a) and (b) of this 

section are not met, the Administrator 

will issue a written disapproval of the 

request to withdraw. The unit covered 

by the request shall continue to be a TR 

SO2 Group 2 opt-in unit. 

(d) Reapplication upon failure to meet 

conditions of withdrawal. If the 

Administrator disapproves the request 

to withdraw, the designated 

representative of the unit may submit 

another request to withdraw in 

accordance with paragraphs (a) and (b) 

of this section. 

(e) Ability to reapply to the TR SO2

Group 2 Trading Program. Once a TR 

SO2 Group 2 opt-in unit withdraws from 

the TR SO2 Group 2 Trading Program, 

the designated representative may not 

submit another opt-in application under 

§ 97.741 for such unit before the date 

that is 4 years after the date on which 

the withdrawal became effective. 

§ 97.743 Change in regulatory status. 

(a) Notification. If a TR SO2 Group 2 

opt-in unit becomes a TR SO2 Group 2 

unit under § 97.704, then the designated 

representative of the unit shall notify 

the Administrator in writing of such 

change in the TR SO2 Group 2 opt-in 

unit’s regulatory status, within 30 days 

of such change. 

(b) Administrator’s actions. (1) If a TR 

SO2 Group 2 opt-in unit becomes a TR 

SO2 Group 2 unit under § 97.604, the 

Administrator will deduct, from the 

compliance account of the source that 

includes the TR SO2 Group 2 opt-in unit 

that becomes a TR SO2 Group 2 unit 

under § 97.704, TR SO2 Group 2 

allowances equal in amount to and 

allocated for the same or a prior control 

period as: 

(i) Any TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 opt-in 

unit under § 97.744 for any control 

period starting after the date on which 

the TR SO2 Group 2 opt-in unit becomes 

a TR SO2 Group 2 unit under § 97.704; 

and 

(ii) If the date on which the TR SO2

Group 2 opt-in unit becomes a TR SO2

Group 2 unit under § 97.704 is not 

December 31, the TR SO2 Group 2 

allowances allocated to the TR SO2

Group 2 opt-in unit under § 97.744 for 

the control period that includes the date 

on which the TR SO2 Group 2 opt-in 

unit becomes a TR SO2 Group 2 unit 

under § 97.704— 

(A) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

SO2 Group 2 opt-in unit becomes a TR 

SO2 Group 2 unit under § 97.704, 

divided by the total number of days in 

the control period, and 

(B) Rounded to the nearest allowance. 

(2) The designated representative 

shall ensure that the compliance 

account of the source that includes the 

TR SO2 Group 2 opt-in unit that 

becomes a TR SO2 Group 2 unit under 

§ 97.704 contains the TR SO2 Group 2 

allowances necessary for completion of 

the deduction under paragraph (b)(1) of 

this section. 

(3)(i) For control periods starting after 

the date on which the TR SO2 Group 2 

opt-in unit becomes a TR SO2 Group 2 

unit under § 97.704, the TR SO2 Group 

2 opt-in unit will be allocated TR SO2

Group 2 allowances in accordance with 

§ 97.712. 

(ii) If the date on which the TR SO2

Group 2 opt-in unit becomes a TR SO2

Group 2 unit under § 97.704 is not 

December 31, the following amount of 

TR SO2 Group 2 allowances will be 

allocated to the TR SO2 Group 2 opt-in 

unit (as a TR SO2 Group 2 unit) in 

accordance with § 97.712 for the control 

period that includes the date on which 

the TR SO2 Group 2 opt-in unit becomes 

a TR SO2 Group 2 unit under § 97.704: 

(A) The amount of TR SO2 Group 2 

allowances otherwise allocated to the 

TR SO2 Group 2 opt-in unit (as a TR SO2

Group 2 unit) in accordance with 

§ 97.712 for the control period; 

(B) Multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the TR 

SO2 Group 2 opt-in unit becomes a TR 

SO2 Group 2 unit under § 97.704, 

divided by the total number of days in 

the control period; and 

(C) Rounded to the nearest allowance. 


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§ 97.744 TR SO2 Group 2 allowance 

allocations to TR SO2 Group 2 opt-in units. 

(a) Timing requirements. (1) When the 

TR opt-in application is approved for a 

unit under § 97.741(g), the 

Administrator will issue TR SO2 Group 

2 allowances and allocate them to the 

unit for the control period in which the 

unit enters the TR SO2 Group 2 Trading 

Program under § 97.741(h), in 

accordance with paragraph (b) of this 

section. 

(2) By no later than October 31 of the 

control period after the control period in 

which a TR SO2 Group 2 opt-in unit 

enters the TR SO2 Group 2 Trading 

Program under § 97.741(h) and October 

31 of each year thereafter, the 

Administrator will issue TR SO2 Group 

2 allowances and allocate them to the 

TR SO2 Group 2 opt-in unit for the 

control period that includes such 

allocation deadline and in which the 

unit is a TR SO2 Group 2 opt-in unit, in 

accordance with paragraph (b) of this 

section. 

(b) Calculation of allocation. For each 

control period for which a TR SO2

Group 2 opt-in unit is to be allocated TR 

SO2 Group 2 allowances, the 

Administrator will issue and allocate TR 

SO2 Group 2 allowances in accordance 

with the following procedures: 

(1) The heat input (in mmBtu) used 

for calculating the TR SO2 Group 2 

allowance allocation will be the lesser 

of: 

(i) The TR SO2 Group 2 opt-in unit’s 

baseline heat input determined under 

§ 97.741(g); or 

(ii) The TR SO2 Group 2 opt-in unit’s 

heat input, as determined in accordance 

with §§ 97.730 through 97.735, for the 

immediately prior control period, 

except when the allocation is being 

calculated for the control period in 

which the TR SO2 Group 2 opt-in unit 

enters the TR SO2 Group 2 Trading 

Program under § 97.741(h). 

(2) The SO2 emission rate (in lb/ 

mmBtu) used for calculating TR SO2

Group 2 allowance allocations will be 

the lesser of: 

(i) The TR SO2 Group 2 opt-in unit’s 

baseline SO2 emission rate (in lb/ 

mmBtu) determined under § 97.741(g) 

and multiplied by 70 percent; or 

(ii) The most stringent State or 

Federal SO2 emissions limitation 

applicable to the TR SO2 Group 2 optin unit at any time during the control 

period for which TR SO2 Group 2 

allowances are to be allocated. 

(3) The Administrator will issue TR 

SO2 Group 2 allowances and allocate 

them to the TR SO2 Group 2 opt-in unit 

in an amount equaling the heat input 

under paragraph (b)(1) of this section, 

multiplied by the SO2 emission rate 

under paragraph (b)(2) of this section, 

divided by 2,000 lb/ton, and rounded to 

the nearest allowance. 

(c) Recordation. (1) The Administrator 

will record, in the compliance account 

of the source that includes the TR SO2

Group 2 opt-in unit, the TR SO2 Group 

2 allowances allocated to the TR SO2

Group 2 opt-in unit under paragraph 

(a)(1) of this section. 

(2) By December 1 of the control 

period after the control period in which 

a TR SO2 Group 2 opt-in unit enters the 

TR SO2 Group 2 Trading Program under 

§ 97.741(h) and December 1 of each year 

thereafter, the Administrator will 

record, in the compliance account of the 

source that includes the TR SO2 Group 

2 opt-in unit, the TR SO2 Group 2 

allowances allocated to the TR SO2

Group 2 opt-in unit under paragraph 

(a)(2) of this section. 

[FR Doc. 2010–17007 Filed 7–30–10; 8:45 am] 

BILLING CODE 6560–50–P 


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