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6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

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

[EPA-HQ-OAR-2009-0491; FRL-____]

RIN 2060-AP50

Federal Implementation Plans to Reduce Interstate Transport of Fine 

Particulate Matter and Ozone in 27 States; Correction of SIP 

Approvals for 22 States

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: In this action, EPA is limiting the interstate transport of 

emissions of nitrogen oxides (NOX) and sulfur dioxide (SO2) that 

contribute to harmful levels of fine particle matter (PM2.5) and ozone 

in downwind states. EPA is identifying emissions within 27 states in 

the eastern United States that significantly affect the ability of 

downwind states to attain and maintain compliance with the 1997 and 

2006 fine particulate matter national ambient air quality standards 

(NAAQS) and the 1997 ozone NAAQS. Also, EPA is limiting these 

emissions through Federal Implementation Plans (FIPs) that regulate 

electric generating units (EGUs) in the 27 states (Alabama, Arkansas, 

Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, 

Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, 

Nebraska, New Jersey, New York, North Carolina, Ohio, Pennsylvania, 

South Carolina, Tennessee, Texas, Virginia, West Virginia, and 

Wisconsin). This action will substantially reduce adverse air 
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quality impacts in downwind states from emissions transported across 

state lines. In conjunction with other federal and state actions, it 

will help assure that all but a handful of areas in the eastern part 

of the country achieve compliance with the current ozone and PM2.5

NAAQS by the deadlines established in the Clean Air Act (CAA or Act). 

The FIPs may not fully eliminate the prohibited emissions from 

certain states with respect to the 1997 ozone NAAQS for two remaining 

downwind areas and EPA is committed to identifying any additional 

required upwind emission reductions and taking any necessary action 

in a future rulemaking. In this action, EPA is also modifying its 

prior approvals of certain State Implementation Plan (SIP)

submissions to rescind any statements that the submissions in 

question satisfy the interstate transport requirements of the CAA or 

that EPA’s approval of the SIPs affects our authority to issue 

interstate transport FIPs with respect to the 1997 fine particulate 

and 1997 ozone standards for 22 states (Alabama, Arkansas, 

Connecticut, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, 

Louisiana, Maryland, Massachusetts, Minnesota, Mississippi, Missouri, 

New York, North Carolina, Ohio, Pennsylvania, South Carolina, 

Virginia, and West Virginia). EPA is also issuing a supplemental 

proposal to request comment on its conclusion that six additional 

states significantly affect downwind states' ability to attain and 

maintain compliance with the 1997 ozone NAAQS.

DATES: This final rule is effective on [INSERT DATE 60 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER].
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ADDRESSES: EPA has established a docket for this action under Docket 

ID No. EPA–HQ–OAR–2009–0491. All documents in the docket are listed 

on the www.regulations.gov website. 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, is not placed on the Internet

and will be publicly available only in hard copy form. Publicly 

available docket materials are available either electronically 

through www.regulations.gov or in hard copy at the EPA Docket Center, 

EPA West, Room B102, 1301 Constitution Avenue, 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: For general questions concerning 

this action, please contact Ms. Meg Victor, Clean Air Markets 

Division, Office of Atmospheric Programs, Mail Code 6204J, 

Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460; telephone number: (202) 343-9193; fax number: 

(202) 343-2359; email address: victor.meg@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; email address:

rodman.sonja@epa.gov.

SUPPLEMENTARY INFORMATION:
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I. Preamble Glossary of Terms and Abbreviations

The following are abbreviations of terms used in the preamble.

AQAT Air Quality Assessment Tool

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

CAMx Comprehensive Air Quality Model with Extensions

CBI Confidential Business Information

CCR Coal Combustion Residuals

CEM Continuous Emissions Monitoring

CENRAP Central Regional Air Planning Association

CFR Code of Federal Regulations

DEQ Department of Environmental Quality

DSI Dry Sorbent Injection

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

GW Gigawatts

Hg Mercury
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ICR Information Collection Request

IPM Integrated Planning Model

km Kilometers

lb/mmBtu Pounds Per Million British Thermal Unit

LNB Low-NOx Burners

MACT Maximum Achievable Control Technology

MATS Modeled Attainment Test Software

μg/m3 Micrograms Per Cubic Meter

MSAT Mobile Source Air Toxics 

MOVES Motor Vehicle Emission Simulator

NAAQS National Ambient Air Quality Standards

NBP NOX Budget Trading Program

NEI National Emission Inventory

NESHAP National Emissions Standards for Hazardous Air 

Pollutants

NOX Nitrogen Oxides

NODA Notices of Data Availability

NSPS New Source Performance Standard

NSR New Source Review

OFA Overfire Air

OSAT Ozone Source Apportionment Technique

OTAG Ozone Transport Assessment Group

ppb Parts Per Billion

PM2.5 Fine Particulate Matter, Less Than 2.5 Micrometers
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PM10 Fine and Coarse Particulate Matter, Less Than 10 

Micrometers

PM Particulate Matter

ppm Parts Per Million

PUC Public Utility Commission

RIA Regulatory Impact Analysis

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SMOKE Sparse Matrix Operator Kernel Emissions

SNCR Selective Non-catalytic Reduction

SO2 Sulfur Dioxide

SOX Sulfur Oxides, Including Sulfur Dioxide (SO2) and 

Sulfur Trioxide (SO3)

TAF Terminal Area Forecast

TCEQ Texas Commission on Environmental Quality

TIP Tribal Implementation Plan

TLN3 Tangential Low NOX

TPY Tons Per Year

TSD Technical Support Document

WRAP Western Regional Air Partnership

II. General Information

A. Does this action apply to me?

This rule affects EGUs, and regulates the following groups:

Industry group NAICSa
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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, and 97,604.

B. How is the preamble organized?

I. Preamble Glossary of Terms and Abbreviations

II. General Information

A. Does this action apply to me?

B. How is the preamble organized?

III. Executive Summary

IV. Legal Authority, Environmental Basis, and Correction of 

CAIR SIP Approvals

A. EPA’s Authority for Transport Rule

B. Rulemaking History

C. Air Quality Problems and NAAQS Addressed

1. Air Quality Problems and NAAQS Addressed

2. FIP Authority for Each State and NAAQS Covered

3. Additional Information Regarding CAA Section 

110(a)(2)(D)(i)(I) SIPs for States in the Transport 

Rule Modeling Domain

D. Correction of CAIR SIP Approvals

V. Analysis of Downwind Air Quality and Upwind State Emissions

A. Pollutants Regulated

1.Background

2.Which pollutants did EPA propose to control for purposes 

of PM2.5 and Ozone Transport?

3.Comments and Responses

B. Baseline for Pollution Transport Analysis
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C. Air Quality Modeling to Identify Downwind Nonattainment and 

Maintenance Receptors

1. Emission Inventories

2. Air Quality Basis for Identifying Receptors

3. How did EPA project future nonattainment and maintenance 

for annual PM2.5, 24-Hour PM2.5, and 8-hour ozone?

D. Pollution Transport from Upwind States

1. Choice of Air Quality Thresholds

2. Approach for Identifying Contributing Upwind States 

VI. Quantification of State Emission Reductions Required

A. Cost and Air Quality Structure for Defining Reductions

1.Summary

2.Background

B. Cost of Available Emission Reductions (Step 1)

1.Development of Annual NOX and Ozone-Season NOX Cost Curves

2.Development of SO2 Cost Curves

3.Amount of Reductions That Could Be Achieved by 2012 and 

2014

C. Estimates of Air Quality Impacts (Step 2)

1.Development of the Air Quality Assessment Tool and Air 

Quality Modeling Strategy

2.Utilization of AQAT to Evaluate Control Scenarios

3.Air Quality Assessment Results

D. Multi-Factor Analysis and Determination of State Emission 

Budgets

1.Multi-Factor Analysis (Step 3)

2.State Emission Budgets (Step 4)

E. Approach to Power Sector Emission Variability

1.Introduction to Power Sector Variability

2.Transport Rule Variability Limits

F. Variability Limits and State Emission Budgets: State 

Assurance Levels 

G. How the State Emission Reduction Requirements are 

Consistent with Judicial Opinions Interpreting the Clean 

Air Act

VII. FIP Program Structure to Achieve Reductions

A. Overview of Air Quality-Assured Trading Programs

B. Applicability

C. Compliance Deadlines

1.Alignment with NAAQS Attainment Deadlines

2.Compliance and Deployment of Pollution Control 

Technologies

D. Allocation of Emission Allowances

1.Allocations to Existing Units

2.Allocations to New Units

E. Assurance Provisions

F. Penalties

G. Allowance Management System

H. Emissions Monitoring and Reporting
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I. Permitting

1.Title V Permitting

2.New Source Review 

J. How the Program Structure is Consistent with Judicial 

Opinions Interpreting the Clean Air Act

VIII. Economic Impacts of the Transport Rule

A. Emission Reductions

B. The Impacts on PM2.5 and Ozone of the Final SO2 and NOX

Strategy

C. Benefits

1.Human Health Benefit Analysis

2.Quantified and Monetized Visibility Benefits

3.Benefits of Reducing GHG Emissions 

4.Total Monetized Benefits

5.How do the benefits in 2012 compare to 2014?

6.How do the benefits compare to the costs of this final 

rule?

7.What are the unquantified and non-monetized benefits of 

the Transport Rule emission reductions?

D. Costs and Employment Impacts

1.Transport Rule Costs and Employment Impacts

2.End-Use Energy Efficiency

IX. Related Programs and the Transport Rule

A. Transition from the Clean Air Interstate Rule

1.Key Differences Between the Transport Rule and CAIR

2.Transition from the Clean Air Interstate Rule to the 

Transport Rule

B. Interactions with NOX SIP Call

C. Interactions with Title IV Acid Rain Program

D. Other State Implementation Plan Requirements

X. Transport Rule State Implementation Plans

XI. Structure and Key Elements of Transport Rule Air QualityAssured Trading Program Rules

XII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

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 and Advancement Act
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J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

1.Consideration of Environmental Justice in the Transport 

Rule Development Process and Response to Comments

2.Potential Environmental and Public Health Impacts among 

Populations Susceptible or Vulnerable to Air Pollution

3.Meaningful Public Participation

4.Summary

K. Congressional Review Act

L. Judicial Review

III. Executive Summary

The 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 final rule, EPA finds that 

emissions of SO2 and NOX in 27 eastern, midwestern, and southern 

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 PM2.5 NAAQS 

promulgated in 1997, the 24-hour PM2.5 NAAQS promulgated in 2006, and 

the ozone NAAQS promulgated in 1997 (EPA uses the term “states” to 

include the District of Columbia in this preamble).

These emissions are transported downwind either as SO2 and NOX

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

ozone. This final rule identifies emission reduction 

responsibilities of upwind states, and also promulgates enforceable 

FIPs to achieve the required emission reductions in each state 

through cost-effective and flexible requirements for power plants. 

Each state has the option of replacing these federal rules with state 
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rules to achieve the required amount of emission reductions from 

sources selected by the state. 

Section 110(a)(2)(D)(i)(I) of the CAA requires the elimination 

of upwind state emissions that significantly contribute to 

nonattainment or interfere with maintenance of a NAAQS in another 

state. Elimination of these upwind state emissions may not 

necessarily, in itself, fully resolve nonattainment or maintenance 

problems at downwind state receptors. Downwind states also have 

control responsibilities because, among other things, the Act 

requires each state to adopt enforceable plans to attain and maintain 

air quality standards. Indeed, states have put in place measures to 

reduce local emissions that contribute to nonattainment within their 

borders. Section 110 (a)(2)(D)(i)(I) only requires the elimination 

of emissions that significantly contribute to nonattainment or 

interfere with maintenance of the NAAQS in other states; it does not 

shift to upwind states the responsibility for ensuring that all areas 

in other states attain the NAAQS.

The reductions obtained through the Transport Rule will help all 

but a few downwind areas come into attainment with and maintain the 

1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5 NAAQS, and the 1997 

ozone NAAQS. With respect to the annual PM2.5 NAAQS, this rule finds 

that 18 states have SO2 and annual NOX emission reduction 

responsibilities, and this rule quantifies each state’s full emission 

reduction responsibility under section 110(a)(2)(D)(i)(I). See Table 

III-1 for the list of these states. With these reductions, EPA 
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projects that no areas will have nonattainment or maintenance 

concerns with respect to the annual PM2.5 NAAQS.

With respect to the 24-hour PM2.5 NAAQS, this rule finds that 21

states have SO2 and annual NOX emission reduction responsibilities, 

and this rule quantifies each state’s full emission reduction 

responsibility under 110(a)(2)(D)(i)(I). See Table III-1 for the 

list of these states. In all, this rule requires emission reductions 

related to interstate transport of fine particles in 23 states. With 

these reductions, as discussed in section VI.D of this preamble, only 

one area (Liberty-Clairton) is projected to remain in nonattainment, 

and three other areas (Chicago,

1 Detroit, and Lancaster) are projected 

to have remaining maintenance concerns for the 24-hour PM2.5 NAAQS.

With respect to the 1997 ozone NAAQS, this rule finds that 20 

states have ozone-season NOX emission reduction responsibilities. For 

10 of these states this rule quantifies the state’s full emission 

reduction responsibility under section 110(a)(2)(D)(i)(I).2 For 10 

additional states, EPA quantifies in this rule the ozone-season NOX

emission reductions that are necessary but may not be sufficient to 

eliminate all significant contribution to nonattainment and

 

1 This area is not currently designated as nonattainment for the 24-

hour PM2.5 standard. EPA is portraying the receptors and counties in 

this area as a single 24-hour maintenance area based on the annual 

PM2.5 nonattainment designation of Chicago-Gary-Lake County, IL-IN.

2 The 10 states for which this rule quantifies the state’s full 

responsibility under section 110(a)(2)(D)(i)(I) with respect to the 

1997 ozone NAAQS are Florida, Maryland, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South Carolina, Virginia, and West 

Virginia.
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interference with maintenance in other states.3 See Table III-1 for 

the complete list of 20 states required to reduce ozone-season NOX

emissions in this rule. With the Transport Rule reductions, only one 

area (Houston) is projected to remain in nonattainment, and one area 

(Baton Rouge) to have a remaining maintenance concern with respect to 

the 1997 ozone NAAQS. The 10 states upwind of either of these two 

areas are the states for which additional reductions may be necessary 

to fully eliminate each state’s significant contribution to 

nonattainment and interference with maintenance, as discussed in 

section VI of this preamble.4

As discussed further below, EPA’s analysis also demonstrates 

that six additional states should be required to reduce ozone-season 

NOX emissions. EPA is issuing a supplemental proposal to request 

comment on requiring ozone-season NOX reductions in these six states. 

For five of these six states, EPA’s analysis identifies the state’s 

full emission reduction responsibility under section 

110(a)(2)(D)(i)(I), and for the remaining one state EPA’s analysis 

 

3 The 10 states for which this rule quantifies reductions that are 

necessary but may not be sufficient to satisfy the requirements of 

110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS are Alabama, 

Arkansas, Georgia, Illinois, Indiana, Kentucky, Louisiana, 

Mississippi, Tennessee, and Texas.

4 This preamble uses the term "significant contribution" only in the

context of the CAA section 110(a)(2)(D)(i)(I) requirement that states

prohibit emissions that "contribute significantly to nonattainment" 

in any other state with respect to any primary or secondary NAAQS. 

Thus, a significant contribution, as used in this preamble, is one 

that is significant for purposes of CAA section 110(a)(2)(D)(i)(I) as 

coming from a particular state.
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identifies reductions that are necessary but may not be sufficient to 

satisfy the requirements of 110(a)(2)(D)(i)(I).5

On January 19, 2010, EPA proposed revisions to the 8-hour ozone 

NAAQS that the Agency had issued March 12, 2008 (75 FR 2938); the 

Agency intends to finalize its reconsideration in the summer of 2011. 

EPA intends to propose a rule to address transport with respect to 

the reconsidered 2008 ozone NAAQS as expeditiously as possible after 

reconsideration is completed. EPA intends to include in that 

proposed rule requirements to address any remaining significant 

contribution to nonattainment and interference with maintenance with 

respect to the 1997 ozone NAAQS for the states identified in this 

final rule, or the associated supplemental notice of proposed 

rulemaking, for which EPA was unable to fully quantify the emissions 

that must be prohibited to satisfy the requirements of 

110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS.

The Act requires EPA to conduct periodic reviews of each of the 

NAAQS. When NAAQS are set or revised, the CAA requires revision of 

SIPs to ensure the standards are met expeditiously and within 

relevant timetables in the Act. If more protective NAAQS are 

 

5 The five states addressed in the supplemental proposal for which 

EPA’s analysis identifies the state’s full reduction responsibility 

under section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS 

are Iowa, Kansas, Michigan, Oklahoma, and Wisconsin. The one state 

addressed in the supplemental proposal for which EPA’s analysis 

identifies reductions that are necessary but may not be sufficient to 

satisfy section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone 

NAAQS is Missouri.
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promulgated, in the case of pollutants for which interstate transport 

is important, additional emission reductions to address transported 

pollution may be required from the power sector, from other sectors, 

and from sources in additional states. EPA will act promptly to 

promulgate any future rules addressing transport with respect to 

revised NAAQS.

The Transport Rule requires substantial near-term emission 

reductions in every covered state to address each state’s significant 

contribution to nonattainment and interference with maintenance 

downwind. This rule achieves these reductions through FIPs that 

regulate the power sector using air quality-assured trading programs 

whose assurance provisions ensure that necessary reductions will 

occur within every covered state. This remedy structure is 

substantially similar to the preferred trading remedy structure 

presented in the proposal. The Transport Rule’s air quality-assured

trading approach will assure environmental results in each state 

while providing market-based flexibility to covered sources through 

interstate trading. The final rule includes four air quality-assured

trading programs: an annual NOX trading program, an ozone-season NOX

trading program, and two separate SO2 trading programs (“SO2 Group 1” 

and “SO2 Group 2”), as discussed further in sections VI and VII, 

below.

The first phase of Transport Rule compliance commences January 

1, 2012, for SO2 and annual NOX reductions and May 1, 2012, for ozoneseason NOX reductions. The second phase of Transport Rule reductions, 
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which commences January 1, 2014, increases the stringency of SO2

reductions in a number of states as discussed further below. 

EPA projects that with the Transport Rule, covered EGU will 

substantially reduce SO2, annual NOX and ozone-season NOX emissions, 

as shown in Tables III-2 and III-3, below. This rule generally 

covers electric generating units that are fossil fuel-fired boilers 

and turbines producing electricity for sale, as detailed in section 

VII.B. 

EPA is promulgating the Transport Rule in response to the remand 

of the Clean Air Interstate Rule (CAIR) by the U.S. Court of Appeals 

for the District of Columbia Circuit (“Court”) in 2008. CAIR, 

promulgated May 12, 2005 (70 FR 25162), required 29 states 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. CAIR covered a similar but not identical set of states as 

the Transport Rule. CAIR FIPs were promulgated April 26, 2006 (71 FR 

25328) to regulate electric generating units in the covered states 

and achieve the emission reduction requirements established by CAIR 

until states could submit and obtain approval of SIPs to achieve the 

reductions.

In July 2008, the Court found CAIR and the CAIR FIPs unlawful. 

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

rehearing, North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 

2008). The Court’s original decision vacated CAIR. North Carolina, 
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531 F.3d 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, 550 F.3d at 1178. The CAIR requirements 

have remained in place while EPA has developed the Transport Rule to 

replace them.

EPA’s approach in the Transport Rule to measure and address each 

state’s significant contribution to downwind nonattainment and 

interference with maintenance is guided by and consistent with the 

Court’s opinion in North Carolina and addresses the flaws in CAIR 

identified by the Court therein. This final rule also responds to 

extensive public comments and stakeholder input received during the 

public comment periods in response to the proposal and subsequent 

Notices of Data Availability (NODAs).

In this action, EPA both identifies and addresses emissions 

within states that significantly contribute to nonattainment or 

interfere with maintenance in other downwind states. In developing 

this rule, EPA used a state-specific methodology to identify emission 

reductions that must be made in covered states to address 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. EPA believes this methodology 

addresses the Court’s concern that the approach used in CAIR was 

insufficiently state-specific. EPA used detailed air quality 
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analysis to determine whether a state’s contribution to downwind air 

quality problems is at or above specific thresholds. A state is 

covered by the Transport Rule if its contribution meets or exceeds 

one of those air quality thresholds and the Agency identifies, using 

a multi-factor analysis that takes into account both air quality and 

cost considerations, emissions within the state that constitute the 

state’s significant contribution to nonattainment and interference 

with maintenance with respect to the 1997 ozone or the 1997 annual or 

2006 24-hour PM2.5 NAAQS. Section 110(a)(2)(D)(i)(I) requires states 

to eliminate the emissions that constitute this “significant 

contribution” and “interference with maintenance.”6

In this final rule, EPA determined the emission reductions 

required from all upwind states to eliminate significant contribution 

to nonattainment and interference with maintenance with respect to 

the 1997 ozone, 1997 annual PM2.5, and 2006 24-hour PM2.5 NAAQS, using, 

in part, an assessment of modeled air quality in 2012 and 2014. EPA 

first identified the following two sets of downwind receptors: (1) 

receptors that EPA projects will have nonattainment problems; and, 

(2) receptors that EPA projects may have difficulty maintaining the 

NAAQS based on historic variation in air quality. To identify areas 

that may have problems attaining or maintaining these air quality 

 

6 In this preamble, EPA uses the terms “significant contribution” and 

“interference with maintenance” to refer to the emissions that must 

be prohibited pursuant to section 110(a)(2)(D)(i)(I) because they 

significantly contribute to nonattainment or interfere with 

maintenance of the NAAQS in another state. 
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standards, EPA projected a suite of future air quality design values, 

based on measured data during the period 2003 through 2007. EPA used 

the average of these future design values to assess whether an area 

will be in nonattainment. EPA used the maximum projected future 

design value to assess whether an area may have difficulty 

maintaining the relevant NAAQS (i.e., whether an area has a 

reasonable possibility of being in nonattainment under adverse 

emission and weather conditions). Section V.C of this preamble 

details the Transport Rule’s approach to identify downwind 

nonattainment and maintenance areas. 

After identifying downwind nonattainment and/or maintenance 

areas, EPA next used air quality modeling to determine which upwind 

states are projected to contribute at or above threshold levels to 

the air quality problems in those areas. Section V.D details the 

choice of air quality thresholds and the approach to determine how 

much each upwind state contributes. States whose contributions meet 

or exceed the threshold levels were analyzed further, as detailed in 

section VI, to determine whether they significantly contribute to 

nonattainment or interfere with maintenance of a relevant NAAQS, and 

if so, the quantity of emissions that constitute their significant 

contribution and interference with maintenance.

When EPA proposed this air-quality and cost-based multi-factor 

approach to identify emissions that constitute significant 

contribution to nonattainment and interference with maintenance from 

upwind states with respect to the 1997 ozone, annual PM2.5, and 2006 
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24-hour PM2.5 NAAQS, the Agency indicated that the approach was 

designed to be applicable to both current and potential future ozone 

and PM2.5 NAAQS (75 FR 45214). EPA believes that the Transport Rule's 

approach of using air-quality thresholds to determine upwind-todownwind-state linkages and using the air-quality and cost-based 

multi-factor approach to determine the quantity of emissions that 

each upwind state must eliminate, i.e., the state's significant 

contribution to nonattainment and interference with maintenance, 

could serve as a precedent for quantifying upwind state emission 

reduction responsibilities with respect to potential future NAAQS, as 

discussed further in section VI.A of this preamble. The Agency 

further believes that the final Transport Rule demonstrates the 

strong value of this approach for addressing the role of interstate 

transport of air pollution in communities’ ability to comply with 

current and future NAAQS.

EPA thus identified specific emission reduction responsibilities 

for each upwind state found to significantly contribute to 

nonattainment or interfere with maintenance in other states. Using 

that information, EPA developed individual state budgets for 

emissions from covered units under the Transport Rule. The Transport 

Rule emission budgets are based on EPA’s state-by-state analysis of 

each upwind state’s significant contribution to nonattainment and 

interference with maintenance. Because each state’s budget is 

directly linked to this state-specific analysis of the state’s 
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obligations pursuant to section 110(a)(2)(D)(i)(I), this approach 

addresses the Court’s concerns about the development of CAIR budgets. 

In this rule, EPA is finalizing SO2 and annual NOX budgets for 

each state covered for the 24-hour and/or annual PM2.5 NAAQS and an 

ozone-season NOX budget for each state covered for the ozone NAAQS. A 

state’s emission budget is the quantity of emissions that will remain 

from covered units under the Transport Rule after elimination of 

significant contribution to nonattainment and interference with 

maintenance in an average year (i.e., before accounting for the 

inherent variability in power system operations).7 

Baseline power sector emissions from a state can be affected by 

changing weather patterns, demand growth, or disruptions in 

electricity supply from other units or from the transmission grid. 

As a consequence, emissions could vary from year to year even in a 

state where covered sources have installed all controls and taken all 

measures necessary to eliminate the state’s significant contribution

to nonattainment and interference with maintenance. As described in 

detail in sections VI and VII of this preamble, the Transport Rule 

accounts for the inherent variability in power system operations 

through “assurance provisions” based on state-specific variability 

limits which extend above the state budgets to form each state’s 

 

7 For the states discussed above for which EPA has quantified the 

minimum amount of emission reductions needed to make measurable 

progress toward satisfying the state’s section 110(a)(2)(D)(i)(I) 

responsibility, the emission budget is the quantity of emissions that 

will remain from covered units after removal of those emissions.
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“assurance level.” The state assurance levels take into account the 

inherent variability in baseline emissions from year to year. The 

final Transport Rule FIPs will implement assurance provisions 

starting in 2012 as discussed in section VII, below.

The emission reduction requirements (i.e., the “remedy”) EPA is 

promulgating in this rule respond to the Court’s concerns that in 

CAIR, EPA had not shown that the emission reduction requirements 

would get all necessary reductions within the state as required by 

section 110(a)(2)(D)(i)(I). The Transport Rule 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 (i.e., the state’s assurance level).

Each state’s Transport Rule SO2, annual NOX, or ozone-season NOX

emission budget is composed of a number of emission allowances 

(“allowances”) equivalent to the tonnage of that specific state 

budget. Under the Transport Rule FIPs, EPA is distributing 

(“allocating”) allowances under each state’s budget to covered units 

in that state. In this rule, EPA analyzed each individual state’s 

significant contribution to nonattainment and interference with 

maintenance and calculated budgets that represent each state’s 

emissions after the elimination of those prohibited emissions in an 

average year. The methodology used to allocate allowances to 

individual units in a particular state has no impact on that state’s 

budget or on the requirement that the state’s emissions not exceed 

that budget plus the variability limit; the allocation methodology 
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therefore has no impact on the rule’s ability to satisfy the 

statutory mandate of CAA section 110(a)(2)(D)(i)(I).

The Transport Rule’s approach to allocate emission allowances to 

existing units is based on historic heat-input data, as detailed in 

section VII.D of this preamble. The Transport Rule SO2, annual NOX, 

and ozone-season NOX emission allowances each authorize the emission 

of one ton of SO2, annual NOX, or ozone-season NOX emissions, 

respectively, during a Transport Rule control period, and are the 

currency in the Transport Rule’s air quality-assured trading 

programs. As discussed in section IX.A.2 below, EPA is creating 

these Transport Rule allowances as distinct compliance instruments 

with no relation to allowances from the CAIR trading programs. EPA 

agrees with the general principle that it is desirable, where 

possible, to provide continuity under successive regulatory trading 

programs, for example through the carryover of allowances from one 

program into a subsequent one. However, EPA is promulgating the 

Transport Rule as a court-ordered replacement for (not a successor 

to) CAIR’s trading programs. In light of the specific circumstances 

of this case, including legal and technical issues discussed in 

Section IX.A.2 below, the final rule will not allow any carryover of 

banked SO2 or NOX allowances from the Title IV or CAIR trading 

programs. EPA will strongly consider administrative continuity of 

this rule’s trading programs under any future actions designed to 

address related problems of interstate transport of air pollution.

A state may submit a SIP revision under which the state (rather 
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than EPA) would determine allocations for one or more of the 

Transport Rule trading programs beginning with vintage year 2013 or 

later allowances.8 Section X of this preamble discusses the final 

rule’s provisions for SIP submissions in detail.

Table III-1 lists states covered by the Transport Rule for PM2.5

and ozone. It also, with respect to PM2.5, identifies whether EPA 

determined the state was significantly contributing to nonattainment 

or interfering with maintenance of the 1997 annual PM2.5 NAAQS, the 

2006 24-hour PM2.5 NAAQS, or both. As discussed below, the Transport 

Rule sorts the states required to reduce SO2 emissions due to their 

contribution to PM2.5 downwind into two groups of varying reduction 

stringency, with “Group 1” states subject to greater SO2 reduction 

stringency than “Group 2” states starting in 2014. Table III-1 also 

lists which SO2 Group each of the states is in. 

Table III-1 - States that Significantly Contribute to Nonattainment 

or Interfere with Maintenance of a NAAQS Downwind in the Final 

Transport Rule

State 1997 Ozone 

NAAQS

1997 

Annual 

PM2.5 NAAQS

2006 24-

Hour PM2.5

NAAQS

SO2

Group

Alabama X X X 2

Arkansas X

Florida X

Georgia X X X 2

 

8

 This final rule allows states to make 2013 allowance allocations 

through the use of a SIP revision that is narrower in scope than the 

other SIP revisions states can use to replace the FIPs and/or to make 

allocation decisions for 2014 and beyond, as discussed in section X.
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Illinois X X X 1

Indiana X X X 1

Iowa X X 1

Kansas X 2

Kentucky X X X 1

Louisiana X

Maryland X X X 1

Michigan X X 1

Minnesota X 2

Mississippi X

Missouri X X 1

Nebraska X 2

New Jersey X X 1

New York X X X 1

North Carolina X X X 1

Ohio X X X 1

Pennsylvania X X X 1

South Carolina X X 2

Tennessee X X X 1

Texas X X 2

Virginia X X 1

West Virginia X X X 1

Wisconsin X X 1

Number of States 20 18 21

As explained in this preamble, EPA has improved and updated both 

steps of its significant contribution analysis. It updated and 

improved the modeling platforms and modeling inputs used to identify 
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states with contributions to certain downwind receptors that meet or 

exceed specified thresholds. It also updated and improved its 

analysis for identifying any emissions within such states that 

constitute the state’s significant contribution to nonattainment or 

interference with maintenance. Therefore, the results of the 

analysis conducted for the final rule differ somewhat from the 

results of the analysis conducted for the proposal.9 

With respect to the 1997 ozone NAAQS, the analysis EPA conducted 

for the proposal did not identify Wisconsin, Iowa and Missouri as 

states that significantly contribute to nonattainment or interfere 

with maintenance of the ozone NAAQS in another state. However, the 

analysis conducted for the final rule shows that emissions from these 

states do significantly contribute to nonattainment or interfere with 

maintenance of the ozone NAAQS in another state. EPA is not issuing 

FIPs with respect to the 1997 ozone NAAQS or finalizing ozone season 

NOX budgets for these states in this rule. EPA is publishing a 

supplemental notice of proposed rulemaking that will provide an 

opportunity for public comment on our conclusion that these states 

significantly contribute to nonattainment or interfere with 

maintenance of the 1997 ozone NAAQS.

In the other direction, the analysis conducted for the proposal 

supported EPA’s conclusion at the time that Connecticut, Delaware, 

 

9 EPA updated its modeling platforms and modeling inputs in response 

to public comments received on the proposed Transport Rule and 

subsequent NODAs and performed other standard updates.
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and the District of Columbia significantly contributed to

nonattainment or interfered with maintenance with respect to the 1997 

ozone NAAQS, whereas the modeling for the final rule no longer 

supports that conclusion for those states.

Additionally, the modeling conducted for the final rule 

identified two ozone maintenance receptors that were not identified 

in the modeling conducted for the proposal -- Allegan County (MI) and 

Harford County (MD). Five states that EPA identified as 

significantly contributing to maintenance problems at the Allegan 

and/or Harford County receptors in the modeling for the final rule 

uniquely contribute to these receptors, i.e., absent these receptors 

the states would not be covered by the Transport Rule ozone-season 

program. The five states that uniquely contribute to these receptors 

are Iowa, Kansas, Michigan, Oklahoma, and Wisconsin. EPA is not 

issuing FIPs with respect to the 1997 ozone NAAQS or finalizing 

ozone-season NOX budgets for these states in this rule. EPA is 

publishing a supplemental notice of proposed rulemaking that will 

provide an opportunity for public comment on our conclusion that 

these states significantly contribute to nonattainment or interfere 

with maintenance of the 1997 ozone NAAQS. 

EPA did not change its methodology between the proposed 

Transport Rule and the final Transport Rule for identifying upwind 

states that significantly contribute to nonattainment or interfere 

with maintenance in other states; nor did EPA change its methodology 

for identifying receptors of concern with respect to maintenance of 
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the 1997 ozone NAAQS. The final rule’s air quality modeling 

identifies the new states and new receptors described above based on 

updated input information (including emission inventories), much of 

which was provided to EPA through public comment on the proposal and 

subsequent NODAs. Section V of this preamble details the approach 

EPA used to identify contributing states and receptors of concern. 

With respect to the annual PM2.5 NAAQS, the analysis EPA 

conducted for the proposal supported EPA’s conclusion that the states 

of Delaware, the District of Columbia, Florida, Louisiana, Minnesota, 

New Jersey, and Virginia were significantly contributing to 

nonattainment and interfering with maintenance of the annual PM2.5

NAAQS while the final rule’s analysis does not. Also, with respect 

to the 24-hour PM2.5 NAAQS, the analysis conducted for the proposal 

supported EPA’s conclusion that the states of Connecticut, Delaware, 

the District of Columbia, and Massachusetts were significantly 

contributing to nonattainment or interfering with maintenance in 

other states while the analysis conducted for the final rule did not.

In the proposal EPA also requested comment on whether Texas 

should be included in the Transport Rule for annual PM2.5. EPA’s 

analysis for the proposal showed that emissions in Texas would 

significantly contribute to nonattainment or interfere with 

maintenance of the annual PM2.5 NAAQS if Texas were not included in 

the rule for PM2.5. The proposal did not include an illustrative 

budget for Texas or illustrative allowance allocations. However, the 

budgets and allowance allocations provided for other states in the 
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proposal were included solely to illustrate the result of applying 

EPA’s proposed methodology for quantifying significant contribution 

to the data EPA proposed to use. EPA provided an ample opportunity 

for comment on this methodology and on the data, including data 

regarding emissions from Texas sources, used in the significant 

contribution analysis. EPA received numerous comments on and 

corrections to Texas-specific data. The modeling conducted for the 

final rule demonstrates that Texas significantly contributes to 

nonattainment or interferes with maintenance of the annual PM2.5 NAAQS 

in another state. EPA provided a full opportunity for comment on 

whether Texas should be included in the rule for annual PM2.5, as well 

as on the methodology and data used for the significant contribution 

analysis for the final rule. EPA therefore believes its 

determination that Texas must be included in the rule for annual PM2.5

is a logical outgrowth of its proposal.

With respect to the 24-hour PM2.5 NAAQS, the analysis EPA 

conducted for the proposal did not identify Texas as a state that 

significantly contributes to nonattainment or interferes with 

maintenance of 24-hour PM2.5 in another state. However, the analysis 

conducted for the final rule shows that emissions from Texas do 

significantly contribute to nonattainment of the 24-hour PM2.5 NAAQS 

in another state. EPA is not issuing a FIP for Texas with respect to 

the 24-hour PM2.5 NAAQS in this rule. However, EPA believes that the 

FIP for Texas with respect to the 1997 annual PM2.5 NAAQS also 

addresses the emissions in Texas that significantly contribute to 
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nonattainment and interference with maintenance of the 2006 24-hour 

PM2.5 NAAQS in another state.

The final rule, however, does not cover the states of 

Connecticut, Delaware, the District of Columbia, Florida, Louisiana, 

or Massachusetts for annual or 24-hour PM2.5 as the analysis for the 

final rule does not support their inclusion. 

The Transport Rule FIPs require the 23 states covered for 

purposes of the 24-hour and/or annual PM2.5 NAAQS to reduce SO2 and 

annual NOX emissions by specified amounts. The FIPs require the 20 

states covered for purposes of the ozone NAAQS to reduce ozone-season 

NOX emissions by specified amounts. As discussed in detail in section 

VI, below, the 23 states covered for the 24-hour and/or annual PM2.5

NAAQS are grouped in two tiers reflecting the stringency of SO2

reductions required to eliminate that state’s significant 

contribution to nonattainment and interference with maintenance 

downwind. The more-stringent SO2 tier (“Group 1”) is comprised of the 

16 states indicated in Table III-1, above, and the less-stringent SO2

tier (“Group 2”) is comprised of the 7 states identified in the 

table. The two SO2 trading programs are exclusive, i.e., a covered 

source in a Group 1 state may use only a Group 1 allowance for 

compliance, and likewise a source in a Group 2 state may use only a 

Group 2 allowance for compliance. In Group 1 states, the SO2

reduction requirements become more stringent in the second phase, 

which starts in 2014.
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In response to the Court’s opinion in North Carolina, EPA has 

coordinated the Transport Rule’s compliance deadlines with the NAAQS 

attainment deadlines that apply to the downwind nonattainment and 

maintenance areas. The Transport Rule requires that all significant 

contribution to nonattainment and interference with maintenance 

identified in this action with respect to the 1997 annual PM2.5 NAAQS 

and the 2006 24-hour PM2.5 NAAQS be eliminated by no later than 2014, 

with an initial phase of reductions starting in 2012 to ensure that 

reductions are made as expeditiously as practicable and, consistent 

with the Court’s remand, to “preserve the environmental values 

covered by CAIR.” Sources must comply by January 1, 2012 and January 

1, 2014 for the first and second phases, respectively.

With respect to the 1997 ozone NAAQS, the Transport Rule 

requires NOX reductions starting in 2012 to ensure that reductions are 

made as expeditiously as practicable to assist downwind state 

attainment and maintenance of the standard. Sources must comply by 

May 1, 2012. The Transport Rule’s compliance schedule and alignment 

with downwind NAAQS attainment deadlines are discussed in detail in 

section VII below.

Table III-2 shows projected Transport Rule emissions compared to 

projected base case emissions, and Table III-3 shows projected 

Transport Rule emissions compared to historical emissions (i.e., 2005 

emissions), for the power sector in all Transport Rule states. The 

ozone-season NOX results shown in Tables III-2 and III-3 are based on 

analysis of the group of 26 states that would be covered for the 
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ozone-season program if EPA finalizes the supplemental proposal 

regarding ozone-season requirements for Iowa, Kansas, Michigan, 

Missouri, Oklahoma, and Wisconsin.

Table III-2 – Projected SO2 and NOX Electric Generating Unit Emission 

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

Emission 

Reductions

2014

Base Case 

Emissions

2014 

Transport 

Rule 

Emissions

2014

Emission 

Reductions

SO2 7.0 3.0 4.0 6.2 2.4 3.9

Annual 

NOX

1.4 1.3 0.1 1.4 1.2 0.2

OzoneSeason 

NOX

0.7 0.6 0.1 0.7 0.6 0.1

* Note that numbers may not sum exactly due to rounding.

** As explained in section V.B, EPA’s base case projections for the 

Transport Rule assume that CAIR is not in place.

Notes:

The SO2 and annual NOX emissions in this table reflect EGUs in the 23 

states covered by this rule for purposes of the 24-hour and/or annual 

PM2.5 NAAQS (Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, Minnesota, Missouri, Nebraska, New 

Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West Virginia, and Wisconsin).

The ozone-season NOX emissions reflect EGUs in the 20 states covered 

by this rule for purposes of the ozone NAAQS (Alabama, Arkansas, 

Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, 

Mississippi, New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West 

Virginia) and the six states that would be covered for the ozone 

NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas, 

Michigan, Missouri, Oklahoma, and Wisconsin).

Table III-3 – Projected SO2 and NOX Electric Generating Unit Emission 

Reductions in Covered States with the Transport Rule Compared to 2005 

Actual Emissions
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(Million Tons)

2005 Actual 

Emissions

2012 

Transport 

Rule

Emissions

2012

Emission

Reductions 

from 2005

2014 

Transport 

Rule

Emissions

2014

Emission

Reductions 

from 2005

SO2 8.8 3.0 5.8 2.4 6.4

Annual 

NOX

2.6 1.3 1.3 1.2 1.4

OzoneSeason 

NOX

0.9 0.6 0.3 0.6 0.3

Notes:

The SO2 and annual NOX emissions in this table reflect EGUs in the 23 

states covered by this rule for purposes of the 24-hour and/or annual 

PM2.5 NAAQS (Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, Minnesota, Missouri, Nebraska, New 

Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West Virginia, and Wisconsin).

The ozone-season NOX emissions reflect EGUs in the 20 states covered 

by this rule for purposes of the ozone NAAQS (Alabama, Arkansas, 

Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, 

Mississippi, New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West 

Virginia) and the six states that would be covered for the ozone 

NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas, 

Michigan, Missouri, Oklahoma, and Wisconsin).

In addition to the emission reductions shown above, EPA projects 

other substantial benefits of the Transport Rule, as described in 

section VIII in this preamble. EPA used air quality modeling to 

quantify the improvements in PM2.5 and ozone concentrations that are 

expected to result from the Transport Rule emission reductions in 

2014. The Agency used the results of this modeling to calculate the 

average and peak reduction in annual PM2.5, 24-hour PM2.5, and 8-hour 

ozone concentrations for monitoring sites in the Transport Rule 
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covered states (including the six states for which EPA issued a 

supplemental proposal for ozone-season NOX requirements) in 2014.

For annual PM2.5, the average reduction across all monitoring 

sites in covered states in 2014 is 1.41 microgram per meter cubed 

(μg/m3) and the greatest reduction at a single site is 3.60 μg/m3. 

For 24-hour PM2.5, the average reduction across all monitoring sites 

in covered states in 2014 is 4.3 μg/m3 and the greatest reduction at a

single site is 11.6 μg/m3. And finally, for 8-hour ozone, the average 

reduction across all monitoring sites in covered states in 2014 is 

0.3 parts per billion (ppb) and the greatest is 3.9 ppb. See section 

VIII for further information on air quality improvements. 

EPA estimated the Transport Rule’s costs and benefits, including 

effects on sensitive and vulnerable and environmental justice 

communities. Table III-4, below, summarizes some of these results. 

Further discussion of the results is provided in preamble section 

VIII, below, and in the Regulatory Impact Analysis (RIA). Estimates 

here are subject to uncertainties discussed further in the RIA.

 

Table III-4. Summary of Annual Benefits, Costs, and Net Benefits of 

the Final Transport Rule in 2014

(Billions of 2007$)a

Description Transport Rule Remedy (Billions of 2007 $)

3 % discount rate 7 % discount rate

Social costs $0.81 $0.81

Total monetized 

benefitsb $120 to $280 $110 to $250

Net benefits 

(benefits-costs)

$120 to $280 $110 to $250
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a All estimates are for 2014, and are rounded to two significant 

figures.

b The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5 and ozone and the welfare 

benefits associated with improved visibility in Class I areas. The 

reduction in premature mortalities account for over 90 percent of 

total monetized PM2.5 and ozone benefits.

As a result of updated analyses and in response to public 

comments, the final Transport Rule differs from the proposal in a 

number of ways. The differences between proposal and final rule are 

discussed throughout this preamble. Some key changes between 

proposal and final rule are that EPA:

 Updated emission inventories (resulting in generally lower base 

case emissions). See section V.C.

 Updated modeling and analysis tools (including improved 

alignment between air quality estimates and air quality modeling 

results). See sections V and VI.

 Updated conclusions regarding which states significantly 

contribute to nonattainment or interfere with maintenance of the 

NAAQS in other states. See Table III-1 and sections V.D and VI.

 Recalculated state budgets and variability limits, i.e., state 

assurance levels, based on updated modeling. See section VI.

 Simplified variability limits for one-year application only. 

See section VI.E.

 Revised allocation methodology for existing and new units and 

revised new unit set-asides for new units in Transport Rule 
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states and new units potentially locating in Indian country. 

See section VII.D.

 Changed start of assurance provisions to 2012 and increased 

assurance provision penalties. See section VII.E.

 Removed opt-in provisions. See section VII.B

 Added provisions for full and abbreviated Transport Rule SIP 

revisions. See section X.

EPA conducted substantial stakeholder outreach in developing the 

Transport Rule, starting with a series of “listening sessions” in the 

spring of 2009 with states, nongovernmental organizations, and 

industry. EPA docketed stakeholder-related materials in the 

Transport Rule docket (Docket ID No. EPA-HQ-OAR-2009-0491). The 

Agency conducted general teleconferences on the rule with tribal 

environmental professionals, conducted consultation with tribal 

governments, and hosted a webinar for communities and tribal 

governments. EPA continued to provide updates to regulatory partners 

and stakeholders through several conference calls with states as well 

as at conferences where EPA officials often made presentations. The 

Agency conducted additional stakeholder outreach during the public 

comment period. EPA responded to extensive public comments received 

during the public comment periods on the proposed rule and associated 

NODAs.

This Transport Rule is one of a series of regulatory actions to 

reduce the adverse health and environmental impacts of the power 
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sector. EPA is developing these rules to address judicial review of 

previous rulemakings and to issue rules required by environmental 

laws. Finalizing these rules will effectuate health and 

environmental protection mandated by Congress while substantially 

reducing uncertainty over the future regulatory obligations of power 

plants, which will assist the power sector in planning for compliance 

more cost effectively. The Agency is providing full opportunity for 

notice and comment for each rule.

As discussed above, rules to address transport under revised 

NAAQS, including the reconsidered 2008 ozone NAAQS, may result in 

additional emission reduction requirements for the power sector. In 

addition, existing Clean Air Act rules establishing best available 

retrofit technology (BART) requirements and other requirements for 

addressing visibility and regional haze may also result in future 

state requirements for certain power plant emission reductions where 

needed.

On May 3, 2011 (76 FR 24976), EPA proposed national emission 

standards for hazardous air pollutants from coal- and oil-fired 

electric utility steam generating units under CAA section 112(d), 

also called Mercury and Air Toxics Standards (MATS), and proposed 

revised new source performance standards for fossil fuel-fired EGUs 

under section 111(b). As discussed in the EPA-led public listening 

sessions during February and March 2011, EPA is preparing to propose 

innovative, cost-effective and flexible greenhouse gas (GHG) 

emissions performance standards under section 111 for steam electric 
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generating units, the largest U.S. source of greenhouse gas 

emissions. On April 20, 2011 (76 FR 22174), EPA proposed 

requirements under section 316(b) of the Clean Water Act for existing 

power generating facilities, manufacturing and industrial facilities 

that withdraw more than two million gallons per day of water from 

waters of the U.S. and use at least twenty-five percent of that water 

exclusively for cooling purposes. On June 21, 2010 (75 FR 35128), 

the Agency proposed to regulate coal combustion residuals (CCRs) 

under the Resource Conservation and Recovery Act to address the risks 

from the disposal of CCRs generated from the combustion of coal at 

electric utilities and independent power producers.

EPA will coordinate utility-related air pollution rules with 

each other and with other actions affecting the power sector 

including these rules from EPA’s Office of Water and its Office of 

Resource Conservation and Recovery to the extent consistent with 

legal authority in order to provide timely information needed to 

support regulated sources in making informed decisions. Use of a 

small number of air pollution control technologies, widely deployed, 

can assist with compliance for multiple rules. EPA also notes that 

the flexibility inherent in the allowance-trading mechanism included 

in the Transport Rule affords utilities themselves a degree of 

latitude to determine how best to integrate compliance with the 

emission reduction requirements of this rule and those of the other 

rules. EPA will pursue energy efficiency improvements in the use of 

electricity throughout the economy, along with other federal 
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agencies, states and other groups, which will contribute to 

additional environmental and public health improvements while 

lowering the costs of realizing those improvements.

IV. Legal Authority, Environmental Basis, and Correction of CAIR SIP 

Approvals

A. EPA’s Authority for Transport Rule

The statutory authority for this action is provided by the CAA, 

as amended, 42 U.S.C. § 7401 et. seq. Section 110(a)(2)(D) of the 

CAA, often referred to as the “good neighbor” provision of the Act, 

and 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 prohibit certain emissions of air pollutants 

because of the impact they would have on air quality in other states. 

42 U.S.C. § 7410(a)(2)(D). This action addresses the requirement in 

section 110(a)(2)(D)(i)(I) regarding the prohibition of emissions 

within a state that will significantly contribute to nonattainment or 

interfere with maintenance of the NAAQS in any other state. EPA has 

previously issued two rules interpreting and clarifying the 

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

promulgated in 1998, was largely upheld by the U.S. Court of Appeals 

for the D.C. Circuit in Michigan, 213 F.3d 663. CAIR, promulgated in 

2005, was remanded by the D.C. Circuit in North Carolina, 531 F.3d 

896, modified on reh’g, 550 F.3d. 1176. These decisions provide 
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additional guidance regarding the requirements of section 

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

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

general authority to prescribe such regulations as are necessary to 

carry out her functions under the Act. 42 U.S.C. § 7601(a)(1). 

Pursuant to this section, EPA has authority to clarify the 

applicability of CAA requirements. In this action, among other 

things, EPA is clarifying the applicability of section 

110(a)(2)(D)(i)(I) by identifying SO2 and NOX emissions that must be 

prohibited pursuant to this section with respect to the PM2.5 NAAQS 

promulgated in 1997 and 2006 and the 8-hour ozone NAAQS promulgated 

in 1997.

Section 110(c)(1) requires the Administrator to promulgate a FIP 

at any time within 2 years after the Administrator finds that a state 

has failed to make a required SIP submission, finds a SIP submission 

to be incomplete or disapproves a SIP submission unless the state 

corrects the deficiency, and the Administrator approves the SIP 

revision, before the Administrator promulgates a FIP. 42 U.S.C. § 

7410(c)(1).

Tribes are not required to submit state implementation plans. 

However, as explained in EPA’s regulations outlining Tribal Clean Air 

Act authority, EPA is authorized to promulgate FIPs for Indian 

country as necessary or appropriate to protect air quality if a tribe 

does not submit and get EPA approval of an implementation plan. See

40 CFR 49.11(a); see also 42 U.S.C. section 7601(d)(4).
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Section 110(k)(6) of the CAA gives the Administrator authority, 

without any further submission from a state, to revise certain prior 

actions, including actions to approve SIPs, upon determining that 

those actions were in error.

B. Rulemaking History

The Transport Rule FIPs will limit the interstate transport of 

emissions of NOX and SO2 within 27 states in the eastern, midwestern, 

and southern United States that affect the ability of downwind states 

to attain and maintain compliance with the 1997 and 2006 PM2.5 NAAQS 

and the 1997 ozone NAAQS.10 Prior to this Transport Rule, CAIR was 

EPA’s most recent regulatory action in a longstanding series of 

regulatory initiatives to address interstate transport of air 

pollution. The proposed Transport Rule preamble provides more 

information on EPA actions prior to CAIR (75 FR 45221-45225).

CAIR, promulgated May 12, 2005 (70 FR 25162), required 29 states 

to adopt and submit revisions to their SIPs to eliminate SO2 and NOX

emissions that contribute significantly to downwind nonattainment of 

the PM2.5 and ozone NAAQS promulgated in 1997. The states covered by 

CAIR were similar but not identical to the states covered by the 

Transport Rule. The CAIR FIPs, promulgated April 26, 2006 (71 FR 

25328), regulated electric generating units in the covered states and 

 

10 As discussed in section III of this preamble, EPA is proposing to 

apply ozone-season NOX requirements to additional states. If EPA 

finalizes that action as proposed, the total number of states covered 

by the Transport Rule FIPs would be 28. 
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achieved CAIR’s emission reduction requirements unless or until 

states had approved SIPs to achieve the required reductions.

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

FIPs unlawful and vacated CAIR. North Carolina, 531 F.3d at 929-30. 

However, the Court subsequently remanded CAIR to EPA without vacatur 

in order to “at least temporarily preserve the environmental values 

covered by CAIR.” North Carolina, 550 F.3d at 1178. CAIR 

requirements have remained in place and CAIR’s emission trading 

programs have operated while EPA developed replacement rules in 

response to the remand.

By promulgating the Transport Rule FIPs, EPA is responding to 

the Court’s remand of CAIR and the CAIR FIPs and replacing those 

rules. The approaches EPA used in the Transport 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 and address the 

flaws in CAIR identified by the Court therein.

By notice of proposed rulemaking (Federal Implementation Plans 

To Reduce Interstate Transport of Fine Particulate Matter and Ozone, 

75 FR 45210; August 2, 2010), EPA proposed the Transport Rule to 

identify and limit NOX and SO2 emissions within 32 states in the 

eastern, midwestern, and southern United States that affect the 

ability of downwind states to attain and maintain compliance with the 

1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. EPA proposed to 

achieve the emission reductions under FIPs, which states may choose 
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to replace by submitting SIPs for EPA approval. EPA proposed to 

limit emissions by regulating electric generating units in the 32 

states with interstate emission trading programs and assurance 

provisions to ensure the required reductions occur in each covered 

state. EPA also requested comment on two alternative FIP remedies.

EPA supplemented the Transport Rule record with additional 

information relevant to the rulemaking in three NODAs for which EPA 

requested comments:

 Notice of Data Availability Supporting Federal Implementation 

Plans to Reduce Interstate Transport of Fine Particulate Matter 

and Ozone (75 FR 53613; September 1, 2010). This NODA provided 

an updated database of unit-level characteristics of EGUs 

included in EPA modeling, an updated version of the power sector 

modeling platform EPA used to support the final rule, and other 

input assumptions and data EPA provided for public review and 

comment.

 Notice of Data Availability Supporting Federal Implementation 

Plans To Reduce Interstate Transport of Fine Particulate Matter 

and Ozone: Revisions to Emission Inventories (75 FR 66055; 

October 27, 2010). This NODA provided additional information 

relevant to the rulemaking, including updated emission inventory 

data for 2005, 2012 and 2014 for several stationary and mobile 

source inventory components.
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 Notice of Data Availability for Federal Implementation Plans To 

Reduce Interstate Transport of Fine Particulate Matter and 

Ozone: Request for Comment on Alternative Allocations, 

Calculation of Assurance Provision Allowance Surrender 

Requirements, New-Unit Allocations in Indian Country, and 

Allocations by States (76 FR 1109; January 7, 2011). This NODA 

provided additional information relevant to the rulemaking, 

including emissions allowance allocations for existing units 

calculated using two alternative methodologies, data supporting 

those calculations, information about an alternative approach to 

calculation of assurance provision allowance surrender 

requirements, allocations for new units locating in Indian 

country in Transport Rule states in the future, and provisions 

for states to submit SIPs providing for state allocation of 

allowances in the Transport Rule trading programs.

C. Air Quality Problems and NAAQS Addressed

1. Air Quality Problems and NAAQS Addressed

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 
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problems. In addition to effects on public health, fine particles 

are linked to a number of public welfare effects, including (1) 

reduced visibility (haze) in scenic areas, (2) effects caused by 

particles settling on ground or water, such as: 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, and (3) staining and damaging of 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 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. 

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. 
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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 

epidemiological evidence indicating a correlation between short-term 

ozone exposure and premature mortality.

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 longlived 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. 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 
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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.

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 anticipates issuing final 

standards soon. 

c. Which NAAQS does this rule address?

This action addresses the requirements of CAA section 

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

(1) the 1997 annual PM2.5 standard,

(2) the 2006 24-hour PM2.5 standard, and

(3) the 1997 ozone standard.

The original CAIR and CAIR FIP rules, which pre-dated the 2006 

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

only.
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In this action, EPA fully addresses, for the states covered by 

this rule, the requirements of CAA section 110(a)(2)(D)(i)(I) for the 

annual PM2.5 standard of 15 μg/m3 and the 24-hour standard of 35 μg/m3. 

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 

covered by this rule, but for the remaining states EPA is conducting 

further analysis to determine whether further requirements are 

needed, as discussed in section III of this preamble.

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.

This action addresses these CAA transport requirements through 

reductions in annual emissions of SO2 and NOX, and through reductions 

in ozone-season NOX. The rationale for these reductions is discussed 

in detail later in the preamble. 

d. Public Comments

EPA received comments on two issues related to the NAAQS 

regulated under the proposed FIPs. 

A number of commenters believed that EPA’s approach to ozone was 

inadequate, and that EPA should not have based the proposed 
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requirements on the 1997 ozone NAAQS. These commenters cited EPA’s 

2008 revision to the standard which lowered the standard to 75 ppb, 

and noted that EPA’s January 2010 proposal for reconsidered ozone 

NAAQS would, if finalized, further lower the primary NAAQS from 75 

ppb to a value between 60 and 70 ppb. Accordingly, many of the 

commenters believed that EPA should have considered the 75 ppb level 

to be the maximum possible value moving forward, and that EPA should 

have used a value no greater than 75 ppb in its analysis.

EPA agrees with commenters that EPA and states should address 

interstate transport with respect to the tighter ozone NAAQS as 

quickly as possible. EPA, as commenters noted, intends to propose a 

second rule to address interstate transport of ozone that will be 

appropriately configured for the revised level of the ozone NAAQS 

after reconsideration of the 2008 standard is finalized. EPA is 

mindful of the need for SIPs to provide for continuing ozone progress 

to meet the 75 ppb level of the 2008 NAAQS, or possibly lower levels 

based on the reconsideration. EPA believes that the ozone-season NOX

requirements of this rule will provide important initial assistance 

to states in this regard. 

Some commenters questioned whether EPA had given states the 

opportunity to provide SIPs addressing transport under the 2006 PM2.5

NAAQS, and thus questioned the appropriateness of the issuance of 

FIPs addressing those NAAQS. Those comments, and EPA’s response, are 

discussed in detail in section IV.C.2.

2. FIP Authority for each State and NAAQS Covered
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The CAA requires and authorizes EPA to promulgate each of the 

Federal Implementation Plans in this final rule. Section 110(c)(1) 

of the CAA requires the Administrator to promulgate a FIP at any time 

within 2 years after the Administrator takes one of three distinct 

actions: (1) she finds that a state has failed to make a required 

SIP submission; (2) she finds a SIP submission to be incomplete; or 

(3) she disapproves a SIP submission. Once the Administrator has 

taken one of these actions with respect to a specific state’s 

110(a)(2)(D)(i)(I) obligation for a specific NAAQS, she has a legal 

obligation to promulgate a FIP to correct the SIP deficiency within 2

years. EPA is relieved of the obligation to promulgate a FIP only if 

two events occur before the FIP is promulgated: (1) the state submits 

a SIP correcting the deficiency; and (2) the Administrator approves 

the SIP revision. 42 U.S.C. § 7410(c)(1).11 

 

11 The CAA provides that EPA is not relieved of its obligation to 

promulgate FIPs unless the state submits a SIP that corrects the 

deficiency and EPA approves the SIP. Nonetheless, in the preamble to 

the proposed rule, EPA indicated that for states not covered by CAIR 

which had 110(a)(2)(D)(i)(I) SIPs pending at the time of proposal, 

EPA would finalize the FIP only if EPA determined the submission was 

incomplete or disapproved the SIP submission. The only two states 

covered by this rule but not covered by CAIR are Kansas and Nebraska. 

Both Kansas and Nebraska are covered by this rule based only on their 

significant contribution to nonattainment or interference with 

maintenance of the 2006 PM2.5 NAAQS. EPA has not received a 

110(a)(2)(D)(i)(I) submission from Nebraska with respect to the 

requirements of the 2006 PM2.5 NAAQS. EPA disapproved a SIP submission 

from Kansas with respect to the requirements of 110(a)(2)(D)(i)(I) 

for the 2006 PM2.5 NAAQS.
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For each FIP in this rule,12 EPA either has found that the state 

has failed to make a required 110(a)(2)(D)(i)(I) SIP submission, or 

has disapproved a SIP submission.13 In addition, EPA has determined, 

in each case, that there has been no approval by the Administrator of 

a SIP submission correcting the deficiency prior to promulgation of 

the FIP. EPA’s obligation to promulgate a FIP arose when the finding 

of failure to submit or disapproval was made, and in no case has it 

been relieved of that obligation.

Some commenters argued that EPA was relieved of its obligation 

to promulgate FIPs when it approved the CAIR SIPs for certain states. 

As an initial matter, EPA notes that this argument applies only to 

EPA’s authority to promulgate FIPs with respect to the 1997 PM2.5

and/or 1997 ozone NAAQS for a subset of states covered by the CAIR. 

It does not apply to EPA’s authority to promulgate FIPs for the 2006 

PM2.5 NAAQS which was not addressed in CAIR. It also does not apply 

to EPA’s authority to promulgate FIPs for the 1997 ozone and 1997 

PM2.5 NAAQS for states that remain subject to the CAIR FIPs, including 

the states that received EPA approval of abbreviated CAIR SIPs which 

 

12 In this action, EPA is issuing 59 FIPs. EPA is issuing 20 FIPs to 

remedy SIP deficiencies relating to the 110(a)(2)(D)(i)(I) 

requirements for the 1997 ozone NAAQS. EPA is also issuing 18 FIPs 

to remedy SIP deficiencies relating to the 1997 PM2.5 NAAQS. Finally, 

EPA is issuing 21 FIPs to remedy SIP deficiencies relating to the 

2006 PM2.5 NAAQS. 

13 The specific findings made and actions taken by EPA are described in 

greater detail in the TSD entitled “Status of CAA 110(a)(2)(D)(i)(I) 

SIPs.” 
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allowed the states to allocate allowances while remaining subject to 

the CAIR FIPs.14

Further, the CAIR SIP approvals do not eliminate EPA’s 

obligation and authority to promulgate a FIP to address the 

requirements of 110(a)(2)(D)(i)(I) because the Court in North 

Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008) found that compliance 

with CAIR does not satisfy the requirement that each state prohibit 

all emissions within the state that significantly contribute to 

nonattainment or interfere with maintenance in another state. The 

Court’s finding that CAIR was unlawful because it did not make 

measureable progress towards the statutory mandate of section 

110(a)(2)(D)(i)(I) meant that the CAIR SIPs were not adequate to 

satisfy that mandate. The CAIR SIPs thus do not correct the SIP 

deficiencies identified in the 2005 findings of failure to submit. 

The SIPs remained in force for the limited purpose allowed by the 

Court –- that is, to achieve interim reductions until EPA promulgated 

a rule to replace CAIR. Given the flaws the court identified with 

CAIR, EPA’s approval of a CAIR SIP does not relieve it of the 

obligation to promulgate FIPs created under section 110(c)(1) of the 

CAA.

Further, to avoid any confusion, EPA has decided to correct, in 

this notice, the full CAIR SIP approvals for states covered by this 

 

14 States may also have received approval to expand the applicability 

of the CAIR NOX ozone season program to include all units subject to 

the NOX Budget Program, allow opt-ins, or provide for distribution of 

a Compliance Supplement Pool under the CAIR NOX (annual) program.
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rule and the CAA 110(a)(2)(D)(i) SIP approvals for states covered by 

CAIR to rescind any statements suggesting that the SIP submissions 

satisfied or relieved states of the obligation to submit SIPs to 

satisfy the requirements of section 110(a)(2)(D)(i)(I) or that EPA 

was relieved of its obligation and authority to promulgate FIPs under 

110(a)(2)(D)(I)(i).

Some commenters further argued that states should be given 

additional time, following promulgation of the Transport Rule, to 

submit a SIP to meet the requirements of section 110(a)(2)(D)(i)(I) 

and that CAIR should remain in place in the meantime. Some 

commenters specifically suggested that EPA restart the “FIP clock”15

to give states this additional time. EPA does not interpret the CAA

as giving it authority to extend the deadline for SIP submissions or 

restart the FIP clock. And nothing in the Act requires EPA to give 

the states another opportunity, following promulgation of the 

Transport Rule, to promulgate a SIP before EPA promulgates a FIP. 

The plain language of section 110(a)(1) of the Act requires the 

submission of SIPs that meet the requirements of 110(a)(2)(D)(i)(I) 

within 3 years after the promulgation of or revision of a primary 

NAAQS. See 42 U.S.C. § 7410(a)(1). Section 110(a)(2)(D)(i)(I) SIPs 

for the 1997 ozone and PM2.5 NAAQS were due in 2000 and 

 

15 “FIP clock” is a term used to describe EPA’s responsibility found 

in CAA Section 110(c)(1) to promulgate a FIP within 2 years after 

either: finding that a state has not submitted a required SIP 

revision or that a submitted SIP revision is incomplete; or 

disapproving a SIP revision.
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110(a)(2)(D)(i)(I) SIPs for the 2006 PM2.5 NAAQS were due in 2009. 

While the statute gives EPA authority to prescribe a shorter period 

of time for states to make these SIP submissions, it does not give 

EPA authority to extend the 3-year deadline established by the Act. 

See 42 U.S.C. § 7410(a)(1). The plain language of section 110(c)(1) 

of the Act, in turn, provides that EPA shall promulgate a FIP at any 

time within 2 years after the Administrator makes a finding of 

failure to make a required SIP submission of disapproves, in whole or 

in part, a SIP submission. See 42 U.S.C. § 7410(c)(1). EPA does not 

have authority to set aside the specific deadlines established in the 

statute, and neither provision allows for the deadlines to be 

extended or to run from promulgation by EPA of a rule to quantify the 

state’s specific obligations pursuant to section 110(a)(2)(D)(i)(I). 

The Act does not require EPA to promulgate a rule or issue guidance 

regarding the specific requirements of section 110(a)(2)(D)(i)(I) in 

advance of the SIP submittal deadline, much less require EPA to 

promulgate such a rule a specific amount of time before the SIP 

submittal deadline. For these reasons, EPA has neither authority to 

alter the SIP submittal deadline nor authority to alter the statute 

provision regarding when EPA’s obligation to promulgate a FIP is 

triggered. 

Finally, EPA does not believe it would be appropriate, in light 

of the Court’s decision in North Carolina, to establish a lengthy 

transition period to the rule that will replace CAIR. The Court 

decision remanding CAIR without vacatur stressed the court’s 
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conclusion that CAIR was deeply flawed and emphasized EPA’s 

obligation to remedy those flaws expeditiously. North Carolina, 550 

F.3d 1176. Although the Court did not set a specific deadline for 

corrective action, the Court took care to note that the effect of its 

opinion would not be delayed “indefinitely” and that petitioners 

could bring a mandamus petition if EPA were to fail to modify CAIR in 

a manner consistent with its prior opinion. Id. Given the Court’s 

emphasis on remedying CAIR’s flaws expeditiously, EPA does not 

believe it would be appropriate to establish a lengthy transition 

period to the rule which is to replace CAIR.

3. Additional Information Regarding CAA Section 110(a)(2)(D)(i)(I) 

SIPs for States in the Transport Rule Modeling Domain

This final rule quantifies out-of-state contributions for the 38 

states that are fully contained within the 12 kilometers (km) eastern 

U.S. modeling domain. EPA is making no specific finding for states 

that are not fully contained within the eastern 12 km modeling 

domain. EPA did not conduct a contribution analysis or make any 

specific finding for New Mexico, Colorado, Wyoming, and Montana since 

they are only partially contained within the 12 km modeling domain. 

With regard to the 1997 PM2.5 NAAQS and 2006 PM2.5 NAAQS, EPA believes 

that states that are included in this 38 state modeling domain will 

meet their section 110(a)(2)(D)(i)(I) obligations to address the 

“significant contribution” and “interference with maintenance” 

requirements by complying with the requirements in this rule. With 

regard to the 1997 ozone NAAQS, EPA believes that states that are 
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included in this 38 state modeling domain will meet their section 

110(a)(2)(D)(i)(I) obligations to address the “significant 

contribution” and “interference with maintenance” requirements by 

complying with the requirements in this rule, except for the 10 

states found to significantly contribute to nonattainment or 

interference of maintenance in either Houston or Baton Rouge (i.e., 

Alabama, Arkansas, Georgia, Illinois, Indiana, Kentucky, Louisiana, 

Mississippi, Tennessee, and Texas). States that are in the 38 state 

modeling domain, and that are not found to be contributing 

significantly to nonattainment or interfering with maintenance for 

any NAAQS evaluated in the modeling for the final rule, could rely on 

this analysis as technical support that their existing or future 

interstate transport SIP submittals are adequate to address the 

transport requirements of 110(a)(2)(D)(i)(I). For example, this rule 

finds that South Carolina significantly contributes to nonattainment 

and interferes with maintenance of the 1997 ozone NAAQS and the 1997 

PM2.5 NAAQS in downwind states. The technical support for the rule 

does not show that South Carolina significantly contributes to 

nonattainment or interferes with maintenance of the 2006 PM2.5 NAAQS 

in downwind states. EPA believes that South Carolina can make a 

negative declaration concluding that the state does not significantly 

contribute to nonattainment or interfere with maintenance in other 

states with regard to the 2006 PM2.5 NAAQS.

D. Correction of CAIR SIP Approvals
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In this action, EPA is also correcting its prior approvals of 

CAIR related SIP submissions and CAA 110(a)(2)(D)(i) SIP submissions 

from Alabama, Arkansas, Connecticut, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, Maryland, Massachusetts, 

Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Virginia and West Virginia to rescind 

any statements that the SIP submissions either satisfy or relieve the 

state of the obligation to submit a SIP to satisfy the requirements 

of section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone and/or 

1997 PM2.5 NAAQS or any statements that EPA’s approval of the SIP 

submissions either relieve EPA of the obligation to promulgate a FIP 

or remove EPA’s authority to promulgate a FIP. This action is based 

on EPA’s determination that those SIP approvals were in error to the 

extent they provided explicitly or implicitly that compliance with 

CAIR satisfies the requirements of 110(a)(2)(D)(i)(I) with respect to 

the 1997 ozone and 1997 PM2.5 NAAQS. The July 2008 decision of the 

D.C. Circuit held, among other things, that the CAIR rule did not 

“achieve[] something measureable toward the goal of prohibiting 

sources ‘within the State’ from contributing to nonattainment or 

interfering with maintenance in ‘any other State.’” North Carolina, 

531 F.3d 908; see also, e.g., id. at 916 (EPA not exercising its 

authority to make measureable progress towards the goals of section 

110(a)(2)(D)(i)(I) because the emission budgets were insufficiently 

related to the statutory mandate). EPA’s actions to approve CAIR SIP 

submittals as satisfying the requirements of section 
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110(a)(2)(D)(i)(I), based on the flawed determination in CAIR that 

compliance with CAIR satisfied those statutory requirements, were 

thus in error as were the separate actions taken to approve section 

110(a)(2)(D)(i)(I) submissions that relied wholly or in part on CAIR.

The approval for Alabama titled “Approval and Promulgation of 

Implementation Plans; Alabama; Clean Air Interstate Rule” which is 

hereby corrected was originally published in the Federal Register on 

October 1, 2007 (72 FR 55659).

The approval for Arkansas titled “Approval and Promulgation of 

Implementation Plans; Arkansas; Clean Air Interstate Rule Nitrogen 

Oxides Ozone Season Trading Program” which is hereby corrected was 

originally published in the Federal Register on September 26, 2007 

(72 FR 54556).

The approval for Connecticut titled “Approval and Promulgation 

of Air Quality Implementation Plans; Connecticut; State 

Implementation Plan Revision to Implement the Clean Air Interstate 

Rule” which is hereby corrected was originally published in the 

Federal Register on January 24, 2008 (73 FR 4105) and the approval 

for Connecticut titled “Approval and Promulgation of Air Quality 

Implementation Plans; Connecticut; Interstate Transport of Pollution” 

which is hereby corrected was originally published in the Federal 

Register on May 7, 2008 (73 FR 25516).

The approval for Florida titled “Approval and Promulgation of 

Implementation Plans; Florida; Clean Air Interstate Rule” which is 
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hereby corrected was originally published in the Federal Register on 

October 12, 2007 (72 FR 58016).

The approval for Georgia titled “Approval and Promulgation of 

Implementation Plans; Georgia; Clean Air Interstate Rule” which is 

hereby corrected was originally published in the Federal Register on 

October 9, 2007 (72 FR 57202).

The approval for Illinois titled “Approval of Implementation 

Plans of Illinois: Clean Air Interstate Rule” which is hereby 

corrected was originally published in the Federal Register on October 

16, 2007 (72 FR 58528).

The approval for Indiana titled “Limited Approval of 

Implementation Plans of Indiana: Clean Air Interstate Rule” which is 

hereby corrected was originally published in the Federal Register on 

October 22, 2007 (72 FR 59480) and the approval for Indiana titled 

“Approval and Promulgation of Air Quality Implementation Plans; 

Indiana; Clean Air Interstate Rule” which is hereby corrected was 

originally published in the Federal Register on November 29, 2010 (75 

FR 72956).

The approval for Iowa titled “Approval and Promulgation of 

Implementation Plans; Iowa; Clean Air Interstate Rule” which is 

hereby corrected was originally published in the Federal Register on 

August 6, 2007 (72 FR 43539) and the approval for Iowa titled 

“Approval and Promulgation of Implementation Plans; Iowa; Interstate 

Transport of Pollution” which is hereby corrected was originally 

published in the Federal Register on March 8, 2007 (72 FR 10380).
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The approval for Kentucky titled “Approval of Implementation 

Plans of Kentucky: Clean Air Interstate Rule” which is hereby 

corrected was originally published in the Federal Register on October 

4, 2007 (72 FR 56623).

The approval for Louisiana titled “Approval and Promulgation of 

Implementation Plans; Louisiana; Clean Air Interstate Rule Sulfur 

Dioxide Trading Program” which is hereby corrected was originally 

published in the Federal Register on July 20, 2007 (72 FR 39741) and 

the approval for Louisiana titled “Approval and Promulgation of 

Implementation Plans; Louisiana; Clean Air Interstate Rule Nitrogen 

Oxides Trading Program” which is hereby corrected was originally 

published in the Federal Register on September 28, 2007 (72 FR 

55064).

The approval for Maryland titled “Approval and Promulgation of 

Air Quality Implementation Plans; Maryland; Clean Air Interstate 

Rule” which is hereby corrected was originally published in the 

Federal Register on October 30, 2009 (74 FR 56117).

The approval for Massachusetts titled “Approval and Promulgation 

of Air Quality Implementation Plans; Massachusetts; State 

Implementation Plan Revision to Implement the Clean Air Interstate 

Rule” which is hereby corrected was originally published in the 

Federal Register on December 3, 2007 (72 FR 67854).

The approval for Minnesota titled “Approval and Promulgation of 

Air Quality Implementation Plans; Minnesota; Interstate Transport of 
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Pollution“ which is hereby corrected was originally published in the 

Federal Register on June 2, 2008 (73 FR 31366).

The approval for Mississippi titled “Approval and Promulgation 

of Implementation Plans; Mississippi: Clean Air Interstate Rule” 

which is hereby corrected was originally published in the Federal 

Register on October 3, 2007 (72 FR 56268).

The approval for Missouri titled “Approval and Promulgation of 

Implementation Plans; Missouri; Clean Air Interstate Rule” which is 

hereby corrected was originally published in the Federal Register on 

December 14, 2007 (72 FR 71073) and the approval of Missouri titled 

“Approval and Promulgation of Implementation Plans; Missouri; 

Interstate Transport of Pollution“ which is hereby corrected was 

originally published in the Federal Register on May 8, 2007 (75 FR 

25975).

The approval for New York titled “Approval and Promulgation of 

Implementation Plans; New York: Clean Air Interstate Rule” which is 

hereby corrected was originally published in the Federal Register on 

January 24, 2008 (73 FR 4109).

The approval for North Carolina titled “Approval of 

Implementation Plans; North Carolina: Clean Air Interstate Rule” 

which is hereby corrected was originally published in the Federal 

Register on October 5, 2007 (72 FR 56914) and the approval for North 

Carolina titled “Approval and Promulgation of Air Quality 

Implementation Plans; North Carolina; Clean Air Interstate Rule” 
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which is hereby corrected was originally published in the Federal 

Register on November 30, 2009 (74 FR 62496).

The approval for Ohio titled “Approval and Promulgation of Air 

Quality Implementation Plans; Ohio; Clean Air Interstate Rule” which 

is hereby corrected was originally published in the Federal Register

on February 1, 2008 (73 FR 6034) and the approval for Ohio titled 

“Approval and Promulgation of Air Quality Implementation Plans; Ohio; 

Clean Air Interstate Rule” which is hereby corrected was originally 

published in the Federal Register on September 25, 2009 (74 FR 

48857).

The approval for Pennsylvania titled “Approval and Promulgation 

of Air Quality Implementation Plans; Pennsylvania; Clean Air 

Interstate Rule; NOX SIP Call Rule; Amendments to NOX Control Rules” 

which is hereby corrected was originally published in the Federal 

Register on December 10, 2009 (74 FR 65446).

The approval for South Carolina titled “Approval of 

Implementation Plans of South Carolina: Clean Air Interstate Rule” 

which is hereby corrected was originally published in the Federal 

Register on October 9, 2007 (72 FR 57209) and the approval for South 

Carolina titled “Approval and Promulgation of Air Quality 

Implementation Plans; South Carolina; Clean Air Interstate Rule” 

which is hereby corrected was originally published in the Federal 

Register on October 16, 2009 (74 FR 53167).

The approval for Virginia titled “Approval and Promulgation of 

Air Quality Implementation Plans; Virginia; Clean Air Interstate Rule 
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Budget Trading Programs” which is hereby corrected was originally 

published in the Federal Register on December 28, 2007 (72 FR 73602).

The approval for West Virginia titled “Approval and Promulgation 

of Air Quality Implementation Plans; West Virginia; Clean Air 

Interstate Rule” which is hereby corrected was originally published 

in the Federal Register on December 18, 2007 (72 FR 71576) and the 

approval for West Virginia titled “Approval and Promulgation of Air 

Quality Implementation Plans; West Virginia; Clean Air Interstate 

Rule” which is hereby corrected was originally published in the 

Federal Register on August 4, 2009 (74 FR 38536).

EPA is taking this final action without prior opportunity for 

notice and comment because EPA finds, for good cause, that notice and 

public procedure thereon are unnecessary and not in the public 

interest. Section 553(b)(B) of the Administrative Procedure Act 

provides that the notice and comment requirements in section 553 do 

not apply when the agency for good cause finds that notice and public 

procedure there on are impracticable, unnecessary, or contrary to the 

public interest. 5 U.S.C. § 553(b)(B). Section 307(d)(1) of the CAA 

in turn provides that the requirements of section 307(d) do not apply 

in the case of a rule or circumstance referred to in section 

553(b)(A) or section 553(b)(B) of the Administrative Procedure Act in 

Title 5. 42 § U.S.C. 7607(1). 

EPA finds that notice and public procedure are unnecessary 

because EPA has no discretion given the specific circumstances 

presented in this case. EPA is bound by the decisions of the courts 
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and must act in accordance with those decisions. EPA must accept the 

Court’s conclusion that compliance with CAIR does not satisfy the 

requirements of CAA section 110(a)(2)(D)(i)(I) and lacks discretion 

to reach a different conclusion. This correction is a ministerial 

matter consistent with the decisions of the courts. For these 

reasons, it is unnecessary to provide an opportunity for notice and 

comment.

V. Analysis of Downwind Air Quality and Upwind State Emissions

A. Pollutants Regulated

To address interstate transport of air pollution, EPA must 

choose which pollutants to regulate relevant to significant 

contribution to nonattainment or interference with maintenance of the 

NAAQS of concern downwind. This section of the preamble discusses 

the pollutants regulated under the final Transport Rule.

1. Background.

Based on scientific and technical information, as well as EPA’s 

air quality modeling, EPA concluded for CAIR that the most effective 

approach to reducing the contribution of interstate transport to PM2.5

was to control SO2 and NOX emissions. For CAIR, EPA did not limit

emissions of 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). 
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With respect to ozone transport, EPA has previously concluded 

that it is proper to control ozone-season NOX emissions. For CAIR and 

the NOX SIP Call programs, EPA based this conclusion on the assessment 

of ozone transport conducted by the Ozone Transport Assessment Group 

(OTAG) in the mid-1990s. The OTAG Regional and Urban Scale Modeling 

and Air Quality Analysis Work Groups concluded that regional NOX

emission reductions are effective in producing ozone benefits that 

grow with increasing regional NOX abatement.

The relative importance of NOX and VOC in ozone formation and 

control varies with local and time-specific factors, including the 

relative amounts of VOC and NOX present. In rural areas and many 

urban 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 large scale stagnation of air masses, which promote the build-up 

of direct emissions and pollutants formed through atmospheric 
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reactions over large regions. Authoritative assessments of ozone 

control approaches have concluded that, for reducing regional scale 

ozone transport, a NOX control strategy is most effective, whereas VOC 

reductions are generally most effective locally, in more dense 

urbanized areas.

Studies conducted since the 1970s established that ozone occurs 

on a regional scale (i.e., thousands of kilometers) over much of the 

eastern U.S., with elevated concentrations occurring in rural as well 

as metropolitan areas. While substantial progress has been made in 

reducing ozone in many urban areas, regional-scale ozone transport is 

still an important component of high ozone concentrations during the 

extended summer ozone season. A series of more recent progress 

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

found on EPA’s website at:

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

More recent assessments of ozone (including those conducted for 

the Regulatory Impact Analysis for the ozone standards in 2008) 

continue to show the importance of NOX transport as a factor in ozone 

formation. For addressing interstate ozone transport in CAIR, EPA 

required NOX emission reductions 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. EPA expects that states, typically in local 

nonattainment planning, would benefit from examining the extent to 

which VOC emissions affect ozone pollution levels within and near 
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urban nonattainment areas, and states may identify areas where multistate VOC strategies might assist in attainment planning for meeting 

the 8-hour standard. However, EPA continues to believe that the most 

effective regional pollution control strategy for mitigation of 

interstate transport of ozone remains NOX emission reductions.

2. Which pollutants did EPA propose to control for purposes of PM2.5

and ozone transport?

For the proposed rule, EPA concluded that its findings in CAIR 

regarding the nature of pollutant contributions are still 

appropriate. EPA proposed to require SO2 and annual NOX emission 

reductions to control PM2.5 transport and to require ozone-season NOX

emission reductions to control ozone transport. In the proposal, EPA 

discussed and requested comment on the inclusion of southern states 

in the annual NOX program for PM2.5 control.

3. Comments and Responses

EPA received no adverse comments on its proposal to regulate SO2

for addressing PM2.5 transport, the proposal not to regulate direct 

PM2.5 or organic PM2.5 precursors, and the proposal to focus ozoneseason efforts on NOX and not to regulate VOCs. 

One commenter questioned EPA’s regulation of NOX for purposes of 

addressing PM2.5 transport in all states (including northern states 

with cooler climates and higher nitrate deposition). Several 

commenters, representing southern state air quality agencies and 

regulated sources in southern states, disagreed with EPA’s proposed 

regulation of annual NOX emissions for all regulated states. These 
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commenters, while not disagreeing with the need for regulation of SO2, 

observed that in EPA’s modeling analysis, contributions from certain 

southern states’ NOX emissions to PM2.5 in downwind states were 

relatively small.

Accordingly, these commenters argued that either (1) EPA should 

remove NOX as a precursor analyzed for PM2.5 contribution from those 

states, or (2) the required remedy for emission reductions in those 

states should not require reductions in annual NOX. 

For the final rule, EPA retains the approach for regulated 

pollutants in the proposal, which regulates annual NOX and SO2 for 

states affecting downwind state PM2.5 nonattainment and maintenance 

sites, and ozone-season NOX for states impacting downwind state ozone 

nonattainment and maintenance. EPA considered commenters’ requests 

to remove some states from the annual NOX program. However, EPA 

believes that it is appropriate to establish a cap on these states’ 

annual NOX emissions, in part to ensure the continued annual operation 

of existing control equipment that would prevent substantial 

increases in NOX emissions. EPA believes that without these 

reductions, increased “nitrate replacement” could occur, a known 

atmospheric phenomenon whereby some of the sulfate reductions due to 

SO2 emission reductions are eroded by increases in nitrate 

concentrations due solely to those SO2 reductions.16 This is an 

 

16 SO2 reductions successfully decrease atmospheric formation of 

ammonium sulfate, but in doing so they “free up” the ammonia 

component that would otherwise have reacted with SO2 and is now free 
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especially pertinent concern for southern states which have 

significant impacts on northern receptors in colder climates where 

nitrate concentrations are generally higher. For example, Alabama 

and Tennessee are both linked to Washtenaw County, MI for 24-hour 

PM2.5; North Carolina is linked to Lancaster County, PA for 24-hour 

PM2.5; and Texas is linked to Madison County, IL for both annual and 

24-hour PM2.5. All of these downwind areas have appreciable nitrate 

deposition contributing to nonattainment and maintenance concerns for 

the PM2.5 NAAQS. If the states linked to those receptors were to make

SO2 reductions only, their beneficial impact on downwind air quality 

would be partially eroded by nitrate replacement. EPA therefore 

believes that it is reasonable to seek both SO2 and NOX reductions 

from states included in the Transport Rule program that are found to 

significantly contribute to nonattainment or interfere with 

maintenance of the PM2.5 NAAQS in downwind states.

In addition, EPA notes that there would be important disbenefits

to effectively removing CAIR’s existing annual NOX requirements in 

those states. If EPA were to allow annual NOX emissions to increase

for those states, there would be potentially harmful effects on 

visibility, nitrogen deposition, and other aspects of human and 

environmental health. 

B. Baseline for Pollution Transport Analysis

 

to react with NOX instead, causing a “rebound effect” partially 

eroding the improvement in PM2.5 concentrations. This effect can be 

mitigated with tandem NOX reductions.
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Implementing the mandate of CAA section 110(a)(2)(D)(i)(I) 

requires EPA to determine which states significantly contribute to 

nonattainment and interfere with maintenance of the NAAQS in other 

states, as well as to quantify the emissions in each state that must 

be eliminated. This process begins with an analysis of baseline 

emissions. Baseline emissions are the emissions that would occur in 

each state if EPA did not promulgate the Transport Rule. To conduct 

such analysis, EPA generally takes into account emission limitations 

that are currently, and will continue to be, in place. From that 

baseline, EPA analyzes whether additional reductions are necessary 

beyond those already mandated by existing emission limitation

requirements. For example, the base case used in CAIR reflected the 

reductions already required by the NOX SIP Call, which remained in 

effect even after the CAIR emission reduction requirements took 

effect.

The unique legal situation addressed by the Transport Rule 

necessarily affects the quantification of baseline emissions. 

Specifically, because the Transport Rule will replace CAIR, EPA 

cannot consider reductions associated with CAIR in the “base case” 

(i.e., analytical baseline emissions scenario). If EPA were to 

consider all reductions associated with CAIR in the “base case,” the 

baseline emissions would not adequately reflect the true 2012 

baseline in each state (i.e., the emissions that would occur in each 

state in 2012 if the Transport Rule did not require any reductions in 

that state). Similarly, if EPA were to treat the capital investments 
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that have already been made to meet the requirements of CAIR as new 

costs rather than treating them as “sunk” capital costs, EPA’s 

analysis would not accurately reflect the cost of emission reductions 

required by the Transport Rule. As explained below, EPA’s analysis 

both properly considered all capital investments made in response to 

CAIR and properly recognized that, after CAIR is terminated, the 

emission limitations imposed by CAIR will cease to exist.

In 2005 EPA promulgated CAIR, which required large electric 

generating units in 29 states to make phase I emission reductions in 

NOX emissions starting in 2009, phase I emission reductions in SO2

starting in 2010 and phase II reductions in emissions of both 

pollutants starting in 2015. On July 11, 2008, the D.C. Court of 

Appeals held that CAIR had “more than several fatal flaws,” North 

Carolina, 531 F.3d at 901, and remanded and vacated the rule, id. at 

930. The Court subsequently granted EPA’s petition for rehearing in 

part and remanded CAIR without vacatur “for EPA to conduct further 

proceedings consistent with” the Court’s July 11, 2008 opinion. 

North Carolina, 550 F.3d 1176. The Court explained that it was 

“allowing CAIR to remain in effect until it is replaced by a rule 

consistent with [the July 11, 2008] opinion” because this “would at 

least temporarily preserve the environmental values covered by CAIR.” 

Id. at 1178. Moreover, the Court stated that it did not “intend to 

grant an indefinite stay of the effectiveness of” the July 11, 2008 

order vacating CAIR. Id. In summary, the Court determined that CAIR 
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was fatally flawed and could remain in effect only as a stopgap 

measure until EPA could act to replace it. 

Thus, unlike most other regulatory requirements (such as the 

Acid Rain Program under CAA Title IV, the NOX Budget Trading Program 

under the NOX SIP Call, New Source Performance Standards, and state 

laws and consent orders requiring emission reductions), the emission 

limitations contained in CAIR are only temporary. Moreover, the 

duration of these limitations is directly tied to the Transport Rule. 

The Transport Rule replaces CAIR. Thus, CAIR itself will be 

terminated for the SO2, annual NOX, and ozone-season NOX control 

periods starting in 2012 when the emission limitations established in 

the final Transport Rule for those control periods take effect 

(January 1, 2012 for the annual control periods and May 1, 2012 for 

the ozone-season control period). For this reason, emission 

reductions made to comply with CAIR cannot be treated as if they were 

emission reductions achieved to comply with statutory provisions, 

rules, consent decrees, and other enforceable requirements that 

establish permanent emission limitations. EPA takes reductions made 

to comply with permanent limitations into consideration when 

quantifying each state’s baseline emissions for the purpose of 

analyzing whether its emissions significantly contribute to 

nonattainment or interfere with maintenance in another state. 

However, the unique legal status of CAIR and its replacement with the 

Transport Rule distinguish the emission reductions required by CAIR 

from those of other regulatory requirements. Since the limitations
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and emission reduction requirements in CAIR are temporary and will be 

terminated by the Transport Rule, they must be excluded from the 

Transport Rule’s base case analysis.

Some comments on the Transport Rule proposal claim that EPA’s 

treatment of CAIR is inconsistent with the treatment, in prior 

rulemakings, of the Acid Rain Program and the NOX SIP Call. Such 

comments ignore the unique legal status of CAIR, and EPA therefore 

rejects these claims.

A simple example illustrates this point. Assume state Z’s 

emissions before CAIR were 2,000 tons and that state Z was required 

by CAIR to reduce its emissions to 1,000 tons. If EPA were to 

determine that state Z’s baseline emissions were 1,000 tons and then 

conclude, based on that assumption, that no additional reductions in 

state Z are necessary because state Z does not significantly 

contribute to downwind nonattainment unless its emissions exceed 

1,500 tons, then state Z would not be covered by the Transport Rule. 

However, the Transport Rule will terminate all CAIR requirements in 

all CAIR states regardless of whether they are covered by the 

Transport Rule. Thus, after promulgation of the Transport Rule, 

state Z would again be allowed, and would be projected in this 

example, to emit 2,000 tons. In other words, state Z would be 

allowed to significantly contribute to nonattainment and/or interfere 

with maintenance in other states -- a result that would be

inconsistent with the statutory mandate of CAA section 

110(a)(2)(D)(i)(I). On the other hand, if EPA assumes state Z’s 
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baseline emissions are 2,000 tons as projected without CAIR in place, 

EPA can properly determine whether, if state Z were allowed to emit 

that amount (i.e., the amount state Z would be projected to emit if 

excluded from the Transport Rule), the state would significantly 

contribute to nonattainment or interfere with maintenance in any 

other state. In other words, EPA can determine the stringency of 

emission limitations needed (if any) to replace those that were 

established by CAIR in order to ensure that state Z prohibits all 

emissions that significantly contribute to nonattainment or interfere 

with maintenance in other states. 

In fact, commenters’ suggestion that the Transport Rule base 

case should include CAIR would cause the anomalous result of 

excluding sources in a state from the Transport Rule because of their 

CAIR–required emission reductions while simultaneously eliminating 

those CAIR emission reduction requirements. If EPA’s base case 

analysis were to assume erroneously that reductions from CAIR would 

continue indefinitely, a state currently covered by CAIR, but not 

covered by the Transport Rule, would have no CAIR requirements once 

the Transport Rule programs began and so could increase emissions 

beyond the CAIR limitations. Downwind areas that are in attainment 

(and are not experiencing interference with maintenance of such 

attainment) solely because of emission reductions required by CAIR 

could again face nonattainment or interference with maintenance 

problems because the current protection from upwind pollution from 

such an upwind state would not be replaced. In short, the analysis 
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of whether a state should be included in a rule eliminating and 

replacing CAIR cannot logically assume that CAIR remains in place. 

For these reasons, EPA believes it is reasonable to use a base case 

that does not assume that the CAIR reduction requirements will 

continue to be achieved and so does not include CAIR-specific 

emission reductions. 

As a result, EPA’s 2012 base case shows emissions higher than 

current levels in some states. In the absence of the CAIR SO2 and NOX

programs that EPA has been directed to eliminate and replace, utility 

emissions in CAIR states will be limited only by non-CAIR constraints 

including the Acid Rain Program, the NOX SIP Call, New Source 

Performance Standards, any state laws and consent order requiring 

emission reductions, and any other permanent and enforceable binding 

reduction commitments. This will lead to increased emissions in some 

states in the 2012 base case relative to current emissions. For 

example, efforts to comply with the Acid Rain Program at the least 

cost may occur, in some cases, without the operation of existing 

scrubbers through use of readily available, inexpensive Title IV 

allowances. 

It is important to note that, to the extent that emission 

reductions currently required by CAIR are also reflected in emission 

reduction requirements under the Acid Rain Program, the NOX SIP Call, 

New Source Performance Standards, any state laws and consent orders

requiring emission reductions, and any other enforceable binding 

reduction commitments, such reductions are accounted for in EPA’s 
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2012 base case. Some commenter claimed that in excluding CAIRspecific emission reductions from the base case, EPA ignores non-CAIR 

legal requirements (e.g., in Title V permits) that may prevent 

sources from increasing emissions above CAIR levels. Such 

allegations are incorrect. As discussed elsewhere in this preamble, 

EPA accounted for any Title V permits, consent decrees, state rules, 

and other enforceable limitations on sources’ emissions; if these 

non-CAIR limitations effectively restrain a state’s emissions to not 

exceed the state’s CAIR limitations, EPA’s base case modeling would 

reflect this outcome. Commenters also assert that utilities are 

unlikely to dismantle or discontinue running the installed controls 

to the point of returning to pre-CAIR emission levels. EPA agrees 

that installed controls are not likely to be physically dismantled, 

and as discussed elsewhere in this preamble, EPA’s analysis properly 

treats the capital investments made in emission controls attributed

to CAIR as “sunk” capital costs (i.e., capital costs already 

obligated in the past) that are not included as costs of meeting 

Transport Rule requirements.

Our cost analysis for significant contribution reflects on-theground realities. Investments in pollution control equipment were 

made in response to CAIR requirements. Those expenditures are “sunk” 

capital costs, meaning that those investments were committed in the 

past, prior to the Transport Rule. Adding the capital costs of that 

equipment into the costs of Transport Rule emission reduction options 
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would be incorrect; those capital investments are represented in 

place in the base case. 

However, given ongoing costs associated with operating these 

controls, EPA believes sources would have an economic incentive to 

discontinue operating installed controls, or to operate those 

controls less effectively, except to the extent non-CAIR legal 

requirements mandate emission reductions or to the extent that 

sources would find it economic to operate the controls for non-CAIR 

market-based emission control programs. EPA properly treats the 

costs of operating controls installed to meet CAIR requirements as 

costs of meeting Transport Rule requirements.17 EPA’s base case 

accounts for non-CAIR requirements and does not make the unreasonable 

assumption that installed controls would be operated to achieve 

emission reductions that are not necessary to meet non-CAIR 

requirements. For all of these reasons, EPA rejects commenters’ 

claims that the base case is “unrepresentative” or lacks “a rational 

relationship to the real world.”

C. Air Quality Modeling to Identify Downwind Nonattainment and 

Maintenance Receptors

 

17 For more details on how EPA models economic operation of existing 

pollution control equipment in the Transport Rule base case, please 

see Section 6 ("Dispatchable Controls") in "Updates to EPA Base Case 

v3.02 EISA Using the Integrated Planning Model" Technical Support 

Document (TSD) for the Transport Rule Docket ID No. EPA-HQ-OAR-2009-

0491, U.S. EPA, July 2010 (available at

http://www.epa.gov/airmarkets/progsregs/epa-ipm/IPM Update 

Documentation.pdf).
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1. Emission Inventories

To inform air quality modeling for the development of the final 

Transport Rule, EPA developed emission inventories for a 2005 base 

year and for 2012 and 2014 projections. The inventories for all 

years include emission estimates for EGUs, non-EGU point sources, 

stationary nonpoint sources, onroad mobile sources, nonroad mobile 

sources, and biogenic (non-human) sources. EPA’s air quality 

modeling relies on this comprehensive set of emission inventories 

because emissions from multiple source categories are needed to model 

ambient air quality and to facilitate comparison of model outputs 

with ambient measurements. In addition, EPA considers all relevant 

emissions (regardless of source category) when determining whether a 

state is found to be significantly contributing to or interfering 

with maintenance of a particular NAAQS in another state.

The emission inventories were processed through the Sparse 

Matrix Operator Kernel Emissions (SMOKE) Modeling System version 2.6 

to produce the gridded, hourly, speciated, model-ready emissions for 

input to the CAMx air quality model. Additional information on the 

development of the emission inventories and related data sets for 

emissions modeling are provided in the Emission Inventory Final 

Transport Rule TSD.

On October 27, 2010, EPA issued a NODA on “Revisions to Emission 

Inventories.” The NODA’s primary purpose was to notify the public 

about changes to emission inventories made since the proposal 

modeling. The affected emission sectors were non-EGU stationary 
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point sources, nonpoint sources, and Category 3 commercial marine 

vessel sources. The NODA also presented a newly released model for 

developing onroad mobile source emissions for use in air quality 

modeling for the final Transport Rule. 

The major comments received in response to the emission 

inventories and modeling included in the proposed Transport Rule and 

the October 27 NODA are summarized in the following subsections. EPA 

agreed with the comments summarized below and adopted technical 

corrections or updates to the emission inventories and modeling 

accordingly. For EPA to be able to take appropriate action, comments 

on the emission inventories needed to be specific enough to allow for 

credible alternative data sources to be located. EPA adopted 

corrections from comments on in-place control programs or devices 

where the controls were enforceable and quantifiable.

a. Foundation Emission Inventory Data Sets

EPA developed emission data representing the year 2005 to 

support air quality modeling of a base year from which future air 

quality could be forecasted. EPA used the 2005 National Emission 

Inventory (NEI), version 2 from October 6, 2008, as the chief basis 

for the U.S. inventories supporting 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. The future base case scenarios modeled for 2012 and 

2014 represent predicted emission reductions primarily from already 

promulgated federal measures. 
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EPA used a 2006 Canadian inventory and a 1999 Mexican inventory 

for the portions of Canada and Mexico within the air quality modeling 

domains for all modeled scenarios. Emissions from Canada and Mexico 

for all source sectors (including EGUs) in these countries were held 

constant for all base- and future-year cases. EPA made this 

assumption because it does not currently have sufficient data to 

support projections of future-year emissions from Canada and Mexico.

b. Development of Emission Inventories for EGUs

The annual NOX and SO2 emissions for EGUs in the 2005 NEI v2 are 

based primarily on data from continuous emissions monitoring systems 

(CEMS), with other EGU pollutants estimated using emission factors 

and annual heat input data reported to EPA. Although only NOX and SO2

are considered for control in this rule, emissions for all criteria 

air pollutants are necessary to model air quality. For EGUs without 

CEMS, EPA used data submitted to the NEI by the states. For more 

information on the details of how the 2005 EGU emissions were 

developed, see the Emissions Inventory Final Rule TSD.

Commenters stated that some point sources that were classified 

as non-EGUs in the proposal modeling were actually EGUs, resulting in 

double counting of emissions in future-year modeling. EPA reviewed

its assignment of EGUs and non-EGUs and reclassified EGU sources 

found to be in the non-EGU inventory for the updated 2005 EGU 

inventory to prevent double counting of future-year emissions.

The future base case scenarios for EGUs reflect projected

changes to fuel usage and economics, as described in the Emission 
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Inventory Final Rule TSD. Future year base case EGU emissions that 

predict SO2, NOX, and PM2.5 were obtained from version 4.10_FTransport 

of the Integrated Planning Model (IPM) outputs 

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

is a multi-regional, dynamic, deterministic linear programming model 

of the U.S. electric power sector; version 4.10_FTransport reflects 

state rules and consent decrees through December 1, 2010, and 

incorporates public comments on existing controls submitted to EPA 

through both the Transport Rule-related notice and comment process as 

well as the proposed Mercury and Air Toxics Standards Information 

Collection Request (ICR). The operation of existing SO2 or NOX

advanced controls (e.g., scrubber, SCR) on units that were not 

required to operate those controls for compliance with Title IV, New 

Source Review (NSR), state settlements, or state-specific rules was 

projected by IPM on the basis of providing least cost operation of 

the power generation system subject to existing regulatory 

requirements except CAIR (see baseline discussion in section V.B). 

Additionally, IPM v.4.10_FTransport incorporates comments 

received during the rulemaking process. Fuel-related updates include 

comment-driven unit-specific limitations on 2012 coal rank selection, 

limiting unrestricted switching from bituminous to subbituminous coal 

by imposing boiler modification costs for those units shifting from 

bituminous to subbituminous coal without historical precedent, and a 

correction of waste coal prices. Pollution control-related updates 

include keying the performance assumptions for FGD and SCR more 
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closely to historic performance data, and the inclusion of dry 

sorbent injection (DSI), a SO2 removal technology. Other notable 

updates include revised assumptions on the heat rate and consequent 

dispatching of cogenerating units and incorporation of additional 

planned retirements. Further details on these updates are available 

in the IPM Documentation, available in the docket and at: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html.

c. Development of Emission Inventories for Non-EGU Point 

Sources

Details on the development of emission inventories are available 

in the Emission Inventory Final Rule TSD. In both the proposal and 

final modeling, controls on industrial boilers installed under the NOX

SIP call were assumed to have been implemented by 2005 and captured 

in the 2005 NEI v2. The non-EGU point source emissions were updated 

from the 2005 NEI and the emissions used for the proposal modeling 

through the incorporation of comments on the proposal emissions 

values, previously unknown facility closures, and through other data 

improvements as identified by EPA analyses. 

EPA does not factor in economic growth to develop non-EGU point 

source emission projections because analysis of historical emission 

trends and economic data did not support using economic growth to 

project non-EGU emissions. More details on the rationale for not 

applying economic growth to non-EGU industrial sources can be found 

in Appendix D of the Regulatory Impact Assessment (RIA) for the PM 

NAAQS rule (http://www.epa.gov/ttn/ecas/regdata/RIAs/Appendix%20D--
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Inventory.pdf). Although projections based on economic growth were 

not included, EPA did include reductions resulting from plant and 

unit closures, local and federal consent decrees, and several Maximum 

Achievable Control Technology (MACT) standards.

For non-EGU point sources, local control programs that may be 

necessary for areas to attain the annual PM2.5 NAAQS and the ozone 

NAAQS are only included in the future base case projections when 

specific information about existing enforceable local controls was 

provided.

Since aircraft at airports were treated as point emissions 

sources in the 2005 NEI v2, we applied projection factors based on 

activity growth projected by the Federal Aviation Administration 

Terminal Area Forecast (TAF) system, published in December 2008. 

A number of comments were received on the stationary non-EGU 

point source inventories. Below is a summary of the major comments 

that impacted the stationary non-EGU point source inventories for the 

final modeling:

Comment: Commenters stated that EPA did not properly represent 

some point source emissions in base-year and future-year inventories 

due to facility and unit closures, consent decrees, emission caps, 

control programs, and alternative emission estimates.

Response: EPA reviewed the sources referenced in the individual 

comments regarding the base-year and future-year inventories. In 

cases where credible alternative data were available, EPA revised the 

emission inventories to incorporate additional facility and unit 
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closures, consent decrees, emission caps, control programs, 

enforceable local controls, and alternative emission estimates.

Comment: Commenters stated that EPA should include controls from 

the National Emission Standards for Hazardous Air Pollutants for 

Reciprocating Internal Combustion Engines (RICE NESHAP) in our 

modeling.

Response: EPA included reductions expected to be achieved by the 

RICE NESHAP across the United States in our final modeling of 

stationary non-EGU and nonpoint sources.

Comment: Commenters stated that EPA was not properly 

representing existing or planned controls for cement plants.

Response: EPA updated control and projection information for 

cement plants based on the latest available data and cement sectorspecific modeling results.

Comment: EPA specifically requested comments on whether to 

incorporate emission reduction estimates from the NESHAP for Major 

Sources: Industrial, Commercial, and Institutional Boilers and 

Process Heaters (75 FR 32006). Commenters stated that emission 

reduction estimates should not be included until the rule became 

final.

Response: EPA did not incorporate emission reduction estimates 

from the NESHAP for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters (75 FR 32006) into the 

proposal or final modeling because the rule was not final at the time 

the modeling was performed. Note that reductions from this rule would 
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not have impacted the 2012 base case due to its implementation 

schedule, and only the 2014 emissions would have been affected.

d. Development of Emission Inventories for Onroad Mobile 

Sources

The onroad emissions in the proposal modeling were primarily 

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

and process level emissions along with gasoline exhaust emissions 

from a fall 2008 draft version of the Motor Vehicle Emission 

Simulator (MOVES). A major comment on the proposal modeling for 

onroad mobile sources was the following:

Comment: Commenters stated that EPA should use a publicly 

released version of MOVES for its final modeling.

Response: EPA updated the final modeling to use data from the 

publicly released version of the MOVES 2010 model because the model 

became available in time for inclusion of its results in the final 

modeling. It was not used for the proposal modeling because it was 

not available at the time the modeling was performed.

In the final Transport Rule modeling, EPA used MOVES 2010 statemonth level emissions for all criteria pollutants and all modes 

(evaporative, exhaust, brake wear and tire wear) and allocated those 

emissions to counties according to state-county NMIM emissions 

ratios. For California (the emissions for which are included to 

support the coarse modeling domain), the onroad mobile emissions data 

were derived from data provided by the state. These data were 

augmented with MOVES 2010 outputs for NH3 because data for that 
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pollutant had not been provided. Additional information on the 

approach to onroad mobile source emissions is available in the 

Emission Inventory Final Rule TSD.

In the future-year base modeling for mobile sources, all 

national measures available at the time of modeling were included. 

The future scenarios for mobile sources reflect projected changes to 

fuel usage, as described in the Emission Inventory Final Rule TSD. 

Emissions for these years reflect onroad mobile control programs 

including the Light-Duty Vehicle Tier 2 Rule, the Onroad Heavy-Duty 

Rule, the Light-Duty Vehicle Greenhouse Gas Rule, the Renewable Fuel 

Standards Rule, and the Mobile Source Air Toxics (MSAT) final rule. 

e. Development of Commercial Marine Category 3 Vessel Emission 

Inventories

For the 2005 modeling, the commercial marine category 3 (C3) 

vessel emissions, a portion of nonroad mobile 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.” 

Emissions out to 200 nautical miles from the coastline were allocated 

to states in the proposal modeling. A major comment on the proposal 

modeling was the following:

Comment: Commenters stated that emissions from commercial marine 

sources (a component of the nonroad emissions in the summaries that 

were provided for the NPR) were too high.
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Response: EPA reviewed the approach used for commercial marine C3

emissions in the proposal. In the final modeling, instead of using 

the boundary of 200 nautical miles from the coast as was used in the 

proposal, EPA adopted the Mineral Management Service state-federal 

water boundaries that assign state waters 3-10 nautical miles from 

the coast. This approach is consistent with the approach used in the 

2005 and 2008 National Emission Inventories. In addition, the 

category 3 commercial marine emissions were adjusted to reflect a 

coordination between the Emissions Control Area proposal to the 

International Maritime Organization (EPA-420-F-10-041, August 2010) 

control strategy; reductions of NOX, VOC, and CO emissions for new C3

engines starting in 2011; and fuel sulfur limits that go into effect 

as early as 2010. 

f. Development of Emission Inventories for Other Nonroad Mobile 

Sources

The nonroad mobile source emissions for sources other than C3

marine were primarily based on NMIM monthly, county, and process 

level emissions from the 2005 NEI v2. These emissions were unchanged 

from proposal modeling, except for PM emissions in California that 

were updated to correct for missing emissions in a few counties and 

source categories. 

Nonroad mobile emissions were created for future years with NMIM 

using an approach consistent with that used for 2005. The nonroad 

emissions for 2012 and 2014 were calculated using NMIM future-year 

equipment population estimates and control programs. Nonroad mobile 
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emission reductions for 2012 and 2014 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 Emission Inventory 

Final Rule TSD.

The 2012 and 2014 nonroad mobile emissions for locomotives and 

category 1 and 2 (C1 and C2) commercial marine vessels were based on 

emissions published in EPA’s Locomotive Marine Rule, Regulatory 

Impact Assessment, Chapter 3. 

g. Development of Nonpoint Emission Inventories

For the proposal Transport Rule modeling, EPA augmented the 2002 

NEI nonpoint emission inventory with a non-California Western 

Regional Air Partnership (WRAP) oil and gas exploration inventory, 

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. For the final Transport Rule modeling, EPA updated 

the nonpoint emission estimates for oil and gas sources. EPA 

continued to use the same WRAP inventory from the proposal, emissions 

in Texas and Oklahoma were updated but for the final modeling with 

data from the Texas Commission on Environmental Quality (TCEQ) and 

the Oklahoma Department of Environmental Quality (DEQ), respectively. 

The average-year county-based inventories for wildfire and 

prescribed burning emissions were unchanged between the proposal and 

final modeling.
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For stationary nonpoint sources, 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 unless 

specific information about existing enforceable controls was 

available (e.g., ozone SIP controls from Ozone Transport Commission 

rules that impact source categories such as Consumer Products, 

Solvent Cleaning, Adhesives and Sealants). EPA specifically requested 

comment on local control data as part of the proposal and the October 

27 NODA, and incorporated any usable data that was provided into the 

final inventories.

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 to future years 

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 

wood stoves with new wood stoves 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.

Some specific adjustments to the inventories were made in the 

final modeling to address comments that were received as described 

below. Area source MACT programs and controls from the RICE NESHAP 
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were included in the final modeling to address submitted comments, as 

were fuel sulfur controls that were enforceable and that take effect 

by 2014.

The major comments that impacted the nonpoint sectors are as 

follows:

Comment: Commenters stated that the SO2 emissions from industrial 

fuel combustion in Nebraska EPA are too high.

Response: EPA reviewed the NEI 2002-based data that had been 

used for the proposal modeling and determined that emissions from the 

2005 inventory compiled for the Central Regional Air Planning 

Association (CENRAP) were more up to date for this source category

and based on more localized data sources. The 2005 CENRAP emissions 

for industrial fuel combustion were used in the final modeling.

Comment: Commenters stated that EPA should include sulfur rule 

controls that take effect prior to the future years that were 

modeled.

Response: EPA included quantifiable sulfur rule controls in 2014 

modeling for those states that had implemented the rules (New Jersey 

and Maine).

Comment: A commenter stated that emissions for Delaware were 

overestimated for several nonpoint categories in base-year and 

future-year inventories and provided alternative estimates for these 

categories.

Response: EPA reviewed the alternative estimates provided and 

found them to be credible and based on more detailed local scale 
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information than were available in the national inventories. EPA 

incorporated the alternative emission estimates for Delaware into the 

final modeling.

Comment: A commenter stated that residual oil is not used as an 

industrial fuel in South Carolina.

Response: EPA analyzed the emissions from residual oil 

industrial fuel combustion in South Carolina and all other states, 

and analyzed preliminary regional planning office inventories and the 

2008 NEI submittals. The South Carolina residual oil industrial fuel 

emissions were determined to be anomalously large in comparison to 

the near zero emissions in other submittals and were therefore 

removed from the nonpoint inventory.

2. Air Quality Basis for Identifying Receptors

a. Introduction

In this section, we describe the final approach to identify 

downwind nonattainment and maintenance receptors. We briefly 

summarize the modeling platform, the proposed approach to identify 

receptors, comments received, and the results of the final analysis.

In the Transport Rule, EPA has explicitly given independent 

meaning to the "interfere with maintenance" prong of section 

110(a)(2)(D)(i)(I) by evaluating contributions to identified 

maintenance receptors as well as contributions to identified 

nonattainment receptors. EPA identified maintenance receptors as 

those receptors that would have difficulty maintaining the relevant 

NAAQS in a scenario that takes into account historic variability in 
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air quality at that receptor. Specifically, EPA projects future air 

quality design values based on measured data during the period 2003 

to 2007. In determining the downwind receptors of concern, EPA does 

not solely rely on the projection of an average design value based on 

measured data from the relevant period (in this case 2003 to 2007) to 

make a determination of "attainment" or "nonattainment." Instead, 

EPA also evaluates the maximum future design value at that receptor 

based on measured data over the relevant period. Receptors for which 

this latter analysis projects design values higher than the NAAQS are 

identified as maintenance receptors. 

EPA believes it is appropriate and reasonable to use this 

approach to identify receptors that may have maintenance problems in 

the future. This approach uses measured data in order to establish 

potential air quality outcomes at each receptor that take into 

account the variable meteorological conditions present across the 

entire period of measured data (2003 to 2007). EPA interprets the 

maximum future design value to be a potential future air quality 

outcome consistent with the meteorology that yielded maximum measured 

concentrations in the ambient data set analyzed for that receptor. 

In other words, the average design value gives a reasonable 

projection of future air quality at the receptor under "average" 

conditions. However, EPA also recognizes that previously experienced 

meteorological conditions (e.g., dominant wind direction, 

temperatures, air mass patterns) promoting ozone or fine particle 

formation that led to maximum concentrations in the measured data may 
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reoccur in the future. The maximum design value gives a reasonable 

projection of future air quality at the receptor under a scenario in 

which such conditions do, in fact, reoccur. It also identifies 

upwind emissions that under those circumstances could interfere with 

the downwind area's ability to maintain the NAAQS. 

Per the court's opinion in North Carolina, it is necessary for 

the Agency to evaluate “interference with maintenance” separately 

from “significant contribution to nonattainment” in order to give 

independent meaning to that phrase in the statute. The approach 

described above does so and provides a reasonable basis for 

identifying upwind emissions that interfere with maintenance of the 

NAAQS at downwind receptors. 

Because the methodology is based on actual variations in design 

values measured at the receptors, EPA believes that the application 

of this design value methodology for identifying maintenance 

receptors reasonably anticipates possible future air quality outcomes 

based on meteorological conditions independent of emission reduction 

requirements occurring between 2005 (the base year for air quality 

analysis) and 2012 (the future year for air quality analysis of the 

base case without CAIR or the Transport Rule in place). EPA uses air 

quality modeling to properly account for changes in air quality from 

2005 to 2012 due to emission control requirements and trends in 

emission source fleet turnover (such as increasingly cleaner motor 

vehicle fleets). The air quality modeling process allows EPA to 

effectively adjust measured data to project design values in 2012 
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based on the forecast changes in emissions. For a given receptor, 

the forecast change in emissions from 2005 to 2012 is a constant 

factor applied across all of the design values from the period 2003 

to 2007. Thus, a comparison of the projected (future-year) design 

values themselves is equivalent to comparing the base period design 

values from the data set to consider how pollution concentrations are

affected by non-modeled factors such as environmental and 

meteorological variability independent of the forecast emission 

reductions that stem from successful imposition of emission 

limitations and controls on various sources between the base and 

future modeling years. EPA believes it is reasonable to anticipate 

that these year-to-year meteorological fluctuations may reoccur at 

any time in the future and are relevant to determining receptors that 

are at risk of having a problem in the future with maintenance of the 

NAAQS. Therefore, EPA assesses the relationship of the maximum 

projected design value for 2012 at each receptor to the relevant 

NAAQS, and where such a value exceeds the NAAQS, EPA determines that 

receptor to be a “maintenance” receptor for purposes of defining 

interference with maintenance under the Transport Rule.

To provide an illustrative example, consider a hypothetical 

receptor “Y” whose measured data for 2003-2007 yields three design 

values for annual fine particles: 17 for 2003-05; 14 for 2004-06; and 

12 μg/m

3 for 2005-07. Thus, the maximum measured design value for 

this period is 17 and the average design value is 14.3. To determine 

whether the receptor is a nonattainment or maintenance receptor, EPA 
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projects a corresponding future-year (2012) design value for each 

measured design value. These projections are based on the results of 

air quality modeling, which demonstrates predicted changes in 

pollution concentrations for each receptor from 2005 to 2012. For 

this example, assume that the projected future-year design values 

that correspond with the measured design values, are 16 (corresponds 

with the 2003-05 design value of 17), 13 (corresponds with the 2004-

06 design value of 14), and 11 μg/m

3 (corresponds with the 2005-07 

design value of 12). The average future-year design value is 13.3 

(corresponds with the average measured design value from 2003-2007 of 

14.3). The projected future design values are all lower than the 

measured design values because air quality is projected to improve 

between 2005 and 2012. In this example, the analysis establishes 

that the average projected future design value is 13.3 and the 

maximum projected future design value is 16. 

The average future (2012) projected design value of 13.3 based 

on the average design value for the period 2003-07 does not exceed 

the 1997 annual PM2.5 NAAQS. For this reason, EPA would conclude that 

receptor Y will most likely have attainment air quality in the future 

year. Therefore, it would not be identified as a nonattainment 

receptor. 

However, the future projected design value of 16 based on the 

maximum design value for the period 2003-07 does exceed the NAAQS. 

For this reason, EPA would conclude that the receptor may have 

difficulty maintaining attainment with the NAAQS under future 
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potential meteorological conditions. EPA therefore would identify 

the receptor as a maintenance receptor and evaluate whether upwind 

state emissions interfere with maintenance of the NAAQS at that 

receptor. 

EPA’s methodology accounts for the range of meteorological 

conditions reflected by design values from the measured 2003-2007 

data at receptor Y and also accounts for the projected changes in 

emissions from 2005 to 2012 at receptor Y. The range of 

meteorological conditions is accounted for by using data from three 

different 3-year periods as described above. The projected changes 

in emissions are accounted for by applying to the measured design 

values the forecasted change in PM2.5 concentrations, as determined 

through air quality modeling of the 2005 and 2012 emissions. In this 

example, the maximum measured design value for receptor Y is 17. 

This design value represents measured data from 2003 to 2005. EPA 

applies to this design value the modeled 2005-to-2012 change in 

concentrations at receptor Y to obtain a 2012 maximum design value 

for that receptor, which is 16. In this way, this maximum 2012 

design value takes into consideration the air quality impacts of all 

known and legally applicable emission limitations taking effect after

the 2003 to 2005 base period. Therefore, each of the projected 

future-year design values provide a fair representation of future air 

quality at receptor Y under different conditions while accounting for 

the emissions projected to remain in 2012. EPA thus believes that if 

one of these future-year design values for a particular receptor 
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exceeds the NAAQS, it is reasonable to conclude that the area may 

have difficulty maintaining that NAAQS. For this reason, EPA 

identifies such receptors as maintenance receptors. In this example, 

EPA would find that while receptor Y’s average future-year design 

value would not exceed the NAAQS, its maximum future-year design 

value (16) would exceed the NAAQS, and it would thus be designated as 

a “maintenance” receptor for purposes of the Transport Rule analyses.

In the proposed rule we used air quality modeling to (1) 

identify locations where we expected there to be nonattainment and/or 

maintenance problems for annual average PM2.5, 24-hour PM2.5, and/or 8-

hour ozone in 2012, (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, and 

(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. 

To support the proposal, air quality modeling was performed for 

four emission 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 emission reductions expected from the FIPs. 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 
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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 2012 

ozone and PM2.5 concentrations were derived by projecting 2003 through 

2007 based ambient ozone and/or PM2.5 data to the future using the 

relative (percent) change in modeled concentrations between 2005 and 

2012. The 2014 base case and 2014 control case modeling were used to 

quantify the benefits of this proposal.

In the proposed rule, EPA used the Comprehensive Air Quality 

Model with Extensions (CAMx) version 5.2018 to simulate ozone and PM2.5

concentrations for the 2005 base year and the 2012 and 2014 future 

year scenarios. 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.

19

CAMx contains “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 

source apportionment tools were used to quantify the downwind 

contributions of ozone and PM2.5 from upwind states. 

 

18 Comprehensive Air Quality Model with Extensions Version 5 User’s 

Guide. Environ International Corporation. Novato, CA. March 2009.

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

modeling domain which covers the lower 48 states and adjacent 

portions of Canada and Mexico. Predictions from this Continental 

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

concentrations for simulations in the 12 km domain.
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In the proposed rule, EPA used a 2005-based air quality modeling 

platform which included 2005 base year emissions and 2005 meteorology 

for modeling ozone and PM2.5 with CAMx.

We received comments related to several aspects of the air 

quality modeling platform. 

Comment: There was wide support from commenters for the use of 

CAMx as an appropriate, state-of-the science air quality tool for use 

in the Transport Rule. There were no comments that suggested that 

EPA should use an alternative model for quantifying interstate 

transport. Many commenters requested that EPA update the emission 

inventories used for the Transport Rule and then remodel the 2005 

base year and future year emissions using the updated emissions and 

the most recent version of CAMx to reassess interstate transport for 

the final rule.

Response: For the final rule we have updated our modeling using 

the latest public release of CAMx (version 5.30) and associated 

preprocessors. We have also made numerous improvements to the 

emission inventories for the 2005 base year as well as the 2012 and 

2014 future year base cases in response to public comments. The 

emissions changes are described in section V.C.1. The projection of 

future year nonattainment and maintenance sites and the 

quantification of ozone and PM2.5 transport for the final rule are 

based on modeling with CAMx v5.30 using the updated emission 

inventories. The final rule air quality projections of 2012 
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nonattainment and maintenance are described below. The final rule 

interstate contributions are presented in section V.D.

Comment: The performance evaluation of the 2005 base year model 

predictions for the proposed rule was too cursory and did not provide 

sufficient detail on model performance. Commenters requested 

additional analyses and spatial resolution describing how well base 

year model predictions compare to the corresponding measured values.

Response: For the final rule we have expanded the scope of the 

model evaluation for 2005 to include a broader suite of statistics to 

characterize performance for individual subregions of the eastern 

U.S. modeling domain. The results of the performance evaluation for 

the final rule 2005 base year air quality modeling are described in 

the Air Quality Modeling Final Rule TSD. 

Comment: The 2005 based modeling platform should be updated to a 

more recent year. There were several different aspects of this 

comment. Some commenters stated that EPA should be using a more 

recent emission inventory as a base year, due to identified changes 

and updates to the inventories. Other commenters stated that EPA 

should use a more recent base year, due to a trend of improvement in 

air quality over the past few years. The commenters claim that the 

2005-based EPA modeling does not account for large emission 

reductions and air quality improvements that have occurred over the 

last several years.

Response: There are several reasons why the use of a 2005 

modeling base case is both reasonable and, in fact, necessary for the 
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Transport Rule. As explained in section V.B, above, because the 

Transport Rule will replace CAIR, EPA cannot consider reductions 

associated with CAIR in the analytical baseline emissions scenario. 

Thus, the base year for the air quality projections should be a year 

that represents emissions before CAIR was in place (i.e. 2005). We 

are projecting emissions to a future 2012 “no CAIR” case and 

therefore want to best represent the air quality change between 2005 

and 2012, without CAIR. To do this, we projected emissions that 

existed before CAIR was in effect and modeled the air quality change 

that occurs between 2005 and 2012 without CAIR. 

A key consideration in our projection methodology is the use of 

ambient data to anchor the design value projections to the future. 

The modeling is used in a relative sense by multiplying the modeled 

percent change in ozone or PM2.5 species concentrations by the base 

year ambient data. The ozone and PM2.5 modeling guidance recommends 

projecting design values based on 5 years20 of monitoring data that is 

centered on the base model year. Using 2005 as a base emissions and 

meteorological year entailed the use of 2003-2007 ambient air quality 

data (5 years of data centered about 2005). This was a reasonable 

choice because the majority of the ambient data from this period was 

not impacted by CAIR emission reductions.

 

20 The modeling guidance recommends using a five year weighted average 

design value. This is calculated by averaging the three consecutive 

design value periods of 2003-2005, 2004-20006, and 2005-2007.
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After 2005, early emission reductions of SO2 and NOX in response 

to CAIR began to impact the measured air quality concentrations. 

Since the modeling projection methodology uses both modeled and 

observed data, 2005 is the latest base year that we deemed 

appropriate (before CAIR emission reductions took place) for use in 

projecting the measured air quality to a 2012 future year. The early 

years of the 5 year period (2003, 2004, and 2005) were not impacted 

by CAIR.

21 The last 2 years in the period (2006 and 2007) were 

slightly impacted by CAIR emission reductions. But the 5 year 

average is weighted towards the middle year of the period (2005), so 

the impact of the years after CAIR promulgation should be minimal.

The 2005 base year was also chosen because it was an appropriate 

meteorological year. In the eastern U.S. there was relatively high 

ozone during the summer of 2005 and relatively high PM2.5 periods 

during the year. The modeled attainment tests for both ozone and 24-

hour PM2.5 depend on having a sufficient number of “high” modeled days 

to project to the future. Modeling a year that is not 

meteorologically conducive to ozone and/or PM2.5 formation is 

discouraged by the modeling guidance because a meteorological year 

that is not conducive to ozone or PM2.5 formation may be less 

responsive to changes in emissions in the future. Therefore, 

projecting the relative change in ozone or PM2.5 for a non-conducive 

 

21 The CAIR final rule was published on May 12, 2005.
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base year may underestimate the future change in ozone and/or PM2.5

concentrations. 

Additionally, all enforceable emission reductions that occurred 

between 2005 and 2012 (other than those required under CAIR) are 

captured by the modeling system. Any enforceable non-EGU emission 

reductions due to existing rules or the installation of emissions 

controls after 2005 were included in the 2012 base case inventory. 

As explained above in section V.B, to capture changes in EGU 

emissions between 2005 and 2012, EPA did not assume operation of all 

controls installed during that time period, as many of those controls 

were built in response to CAIR. EPA used IPM to project 2012 EGU 

emissions incorporating all non-CAIR enforceable emission 

constraints; operation of existing pollution controls was taken into 

account only where non-CAIR constraints made it economic or legally 

necessary to operate them. We also accounted for permanent source 

shutdowns that occurred after 2005. Where possible, we incorporated 

reported emission changes based on comments to the proposed rule and 

a subsequent emission inventory NODA.

Comment: Several commenters stated that we used a “modeled + 

monitored” test in CAIR to identify future year nonattainment 

receptors, but we only used a modeled test in the Transport Rule 

proposal. They suggest that we should either go back to the “modeled 

+ monitored” test or explain why we should not use monitoring data in 

the identification of nonattainment and maintenance receptors. They 

say that we should not base nonattainment and maintenance receptors 
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solely on modeled violations. They also say that we if we had looked 

at the most recent ambient data we would see that most of the modeled 

nonattainment and maintenance receptors are already attaining the 

ozone and/or PM2.5 NAAQS.

Response: In the identification of future year nonattainment 

receptors for CAIR, EPA used what was called the “modeled + monitored 

test”. The most recent ambient data (2001-2003 design values at the 

time) were examined to further verify that nonattainment was still 

being measured at potential future year nonattainment receptors. In 

the proposed Transport Rule, EPA identified future year nonattainment 

and maintenance receptors based on modeled projections of ambient 

data from the 2003-2007 time period. The future year receptors were 

not compared to most recent ambient data to verify that nonattainment 

still existed.

For the final Transport Rule, there are several reasons that EPA did 

not examine the most recent ambient data to verify that receptors 

were still measuring nonattainment. The main reason for dropping the 

“monitored” part of the modeled + monitored test is the fact that the 

most recent monitoring data (2007-2009 design values) include large 

emission reductions from CAIR. As explained in section V.B, above, 

because the Transport Rule will replace CAIR, we must model a future 

year base case which does not assume that CAIR is in place (a “noCAIR” case). It is simply not appropriate to examine the current 

monitoring data, which represent air quality with CAIR emission 

reductions in place, and compare the values to 2012 projected air 
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quality that is based on a no-CAIR modeling case. As discussed 

above, we modeled a 2005 base case with pre-CAIR emissions and a 2012 

future “no CAIR” case. The change in modeled air quality is due to 

the non-CAIR enforceable emission changes between 2005 and 2012 and 

therefore explicitly does not take CAIR into account. As a 

consequence, the 2012 projected design values represent a unique case 

(necessary for analyzing future air quality without either CAIR or 

its replacement Transport Rule in effect) that cannot be represented 

by current ambient data. 

It is also important to note that all of the projected 2012 

design values are based on projections of measured ambient data. 

They are a combination of measured data and modeled response factors. 

Therefore, it is inaccurate to imply that future year nonattainment 

and maintenance receptors are solely based on modeled projections. 

The future year concentrations are firmly rooted in base year 

measured ambient data that have been projected to the future using 

modeled data. 

There are additional reasons for not verifying the nonattainment 

and maintenance receptors against the most recent ambient data. In 

CAIR we did not explicitly identify maintenance receptors. In the 

Transport Rule proposal we identified maintenance receptors based on 

2012 projections of maximum design values from the 2003-2007 period. 

Even though receptors may be measuring attainment based on recent 

data, they may still be at risk for falling back into nonattainment. 

Therefore, even if commenters argue that recent data show that 
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monitoring sites should not be nonattainment receptors (with which we 

disagree), the same argument cannot be made regarding maintenance 

receptors. Clearly, receptors with recent “clean” ambient data may 

still experience higher PM2.5 and/or ozone concentrations in the 

future (based on meteorological and emission variability) and 

therefore may be appropriate maintenance receptors. Comment: 

Several commenters claim that the maintenance receptor methodology 

overstates actual future design values. They also recommend an 

alternative methodology which takes into account the downward trend 

in observed PM2.5 concentrations over the last 5+ years. The 

methodology would remove the trend in the data where air quality is 

improving over the period by applying a linear fit to the data, 

calculating the residuals and then adding the residuals back to the 

average of the data. Given a site with a downward trend, this has 

the effect of decreasing the calculated maximum values from the early 

years in the period and increasing the values from the end years in 

the period. 

Response: EPA continues to believe that our approach to identify 

maintenance receptors is reasonable and appropriate. For the final 

rule, we continue to identify maintenance receptors by projecting the 

maximum design value from the 2003-2007 period to the future. The 

methodology assumes that the combination of emissions and meteorology 

that occurred in the base period (which led to relatively high 

ambient design values) could happen again in the future (albeit at 

lower emissions levels). There is no information presented by the 
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commenters which explains why the magnitude of base year design value 

variability could not occur in the same way in the future. The 

commenters cite the downward trend in ambient data as the reason why 

the EPA methodology is not reasonable. However, in most cases, the 

recent downward trend in ambient data is due to a combination of 

ongoing emission reductions (which includes CAIR), variability in 

meteorology, and depressed emissions due to the recession. In fact, 

the most recent ambient design value period (2007-2009) is heavily 

influenced by extremely low ozone and PM2.5 concentrations measured in 

2009. The 2009 data are marked by relatively low emissions due to 

cool summer weather and ongoing effects of the recession. The 

preliminary22 2010 ambient data in the eastern U.S. show that ozone 

and PM2.5 values were considerably higher in 2010 compared to 2009. 

In the states that are included in the final Transport Rule region, 

there were 158 ozone monitor days that exceeded 84 ppb in 2009 

compared to 412 monitor exceedance days in 2010. For PM2.5, there 

were 251 monitor days that exceeded 35 μg/m3 in 2009 compared to 417 

monitor exceedance days in 2010. Even though the SO2 and NOX

emissions were generally lower in 2010, the observed ozone and PM2.5

concentrations were higher. This shows the important influence of 

meteorology on ambient concentrations. Clearly, the year to year 

variability due to meteorology can be large. We acknowledge the 

downward trend in ambient data over the last few years. But this 

 

22 The 2010 data is preliminary. Exceptional event data has not been 

flagged and removed from the reported data. 
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does not mean that conditions that led to high ozone and/or PM2.5 in 

the 2003-2007 period could not occur again in the future. The 2010 

ambient data show that meteorology can cause concentrations to go 

back up, even though there is a downward trend in emissions. 

We also believe that the alternate maintenance methodology 

presented by the commenter is inappropriate. The EPA modeling for 

2012 (and 2014) appropriately accounts for emission reductions that 

occur after 2005 except for those that should not be considered, as 

explained in section V.B., because they were required only by CAIR. 

Therefore, the starting point design values used to project to the 

future should not be lowered to account for emission reduction trends 

that occur after 2005. Doing so would give “double credit” to the 

more recent emission reductions and provides an inappropriate 

downward adjustment to the early design value periods of the 2003-

2007 period.

Comment: One commenter claims that EPA did not follow our own 

modeling guidance by not doing local scale modeling in urban areas 

with high PM2.5 concentration gradients. They suggested that the 

methodology to calculate future year design values should have 

included dispersion modeling to calculate the change in concentration

over time of primary PM2.5 emissions. 

Response: EPA modeling guidance for PM2.5 attainment 

demonstrations recommends photochemical grid modeling to examine 

future year changes in PM2.5 concentrations. There are several 

optional aspects of the modeling which are recommended in specific 
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cases. This includes a recommendation for a “local area analysis” 

using a dispersion model. An area with relatively large local 

primary PM2.5 concentration gradients may want to do additional 

modeling to examine the impacts of local controls on its future year 

PM2.5 concentrations. This is particularly important when local 

controls of primary PM2.5 are included as part of the attainment 

demonstration. 

As noted above, a “local area analysis” is recommended as part 

of the local attainment demonstration process in specific situations. 

It is impractical for EPA to perform this type of analysis for each 

local area in the regional Transport Rule. National rulemakings are 

not attainment demonstrations. We are not able to perform fine scale 

analyses for each area. For the final rule modeling, we have 

attempted to address all emissions and modeling related comments. We 

have updated the modeling platform to use the latest version of CAMx 

and are continuing to model ozone and PM2.5 at 12km grid resolution, 

which for PM2.5 is a more refined grid resolution compared to the CAIR 

modeling. 

Additionally, there is no evidence presented by the commenter 

that would indicate that the future year PM2.5 concentrations from the 

Transport Rule are biased high. In fact, depending on the 

circumstances, local fine scale grid or dispersion modeling may 

result in lower or higher future year design values. In a fine scale 

analysis, the dominant local primary PM2.5 emissions become a larger 

percentage of the PM2.5 concentrations. Therefore, if the local 
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emissions are forecast to decrease, fine scale modeling may lead to 

lower future design values. However, if the local emissions are 

forecast to increase or stay the same between the base and future 

years, local modeling will likely show higher future year design 

values compared to a regional analysis. This points to the fact that 

perceived biases in modeling results may not always be correct. 

In sum, fine scale modeling of local areas may lead to either 

higher or lower future year design values. There is no indication 

that EPA’s regional modeling is biased in either direction. EPA’s 

Transport Rule modeling generally followed EPA’s modeling guidance 

and is appropriate for the purpose of this rulemaking.

Comment: One commenter completed and submitted a detailed CAMx 

based modeling analysis with a 2008 base year and future years of 

2014 and 2018. The analysis shows that the majority of the proposed 

rule 2012 nonattainment and maintenance sites are already attaining 

based on either 2006-2008 or 2007-2009 ambient data. Based on this, 

the commenter claims that air quality has improved more rapidly than 

predicted by EPA’s proposed rule modeling. Also, based on the 

commenter’s 2014 modeling of CAIR emissions (including utility 

consent decrees and state programs), the commenter concludes that no 

additional controls are needed beyond CAIR to bring most or all sites 

into attainment by 2014. 

Response: As an initial matter, we note that the basic question 

addressed by the commenter, “whether additional controls beyond CAIR 

are necessary,” is not on point. As explained previously, the D.C. 
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Circuit remanded CAIR to EPA and it remains in place only 

temporarily. The question EPA must answer in this rulemaking, 

therefore, is not what controls in addition to CAIR are necessary but 

what, if any, restrictions on emissions must be put in place to 

replace CAIR in order to satisfy the requirements of section 

110(a)(2)(D)(i)(I) of the CAA. For this reason, and as explained in 

greater detail in section V.B of this preamble, any analysis of 

whether beyond CAIR controls are necessary is irrelevant to this 

rulemaking. Nonetheless, we have carefully reviewed different 

aspects of the commenter’s analysis. We previously addressed 

comments related to the use of more recent ambient data to examine 

future year nonattainment and maintenance receptors. As noted above, 

the 2006-2008 and 2007-2009 ambient data is heavily influenced by 

several factors. Among them are the emissions reductions from CAIR, 

the relatively low recent observed ozone and PM2.5 concentrations at

least partially due to non-conducive meteorology (particularly in 

2009), and the atypical suppression of emissions due to the sharp 

recession. For all of these reasons, we believe it is not possible 

to directly compare the most recent design values to the predicted 

future year 2012 and 2014 design values from the Transport Rule. In 

particular, it is inappropriate to compare current design values to 

EPA’s no-CAIR 2012 future year modeling results. As noted in the 

comment summary, the commenter’s modeling analysis assumed that CAIR 

was in place in both 2008 and the future years. This is a 

fundamentally different assumption than the modeling EPA used to 
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define the Transport Rule nonattainment and maintenance receptors in 

2012 and is inappropriate for purposes of the Transport Rule for 

reasons described above and in section V.B.

Additionally, EPA’s maintenance methodology chooses the highest 

of three base year design value periods projected to the future. The 

commenter only used a single design value period in their analysis 

and therefore did not fully examine maintenance issues. In fact, the 

2014 nonattainment modeling receptors in the final Transport Rule and 

the commenter’s modeling analysis are similar. As documented in 

section VI.D, in the 2014 final rule remedy case, there is only one 

remaining nonattainment area for ozone and one remaining 

nonattainment area for 24-hour PM2.5. This is similar to the modeling 

results presented in the comments.

23 However, EPA modeling identifies 

additional maintenance receptors in 2012 that continue to have 

maintenance issues in 2014. 

EPA also examined our ozone and PM2.5 projection procedures to 

see if there might be additional reasons for the relatively lower 

current ambient design values (and modeled design values in the 

commenter’s analysis) compared to the 2014 remedy modeled values. 

Upon further analysis of EPA’s 24-hour attainment test methodology, 

we noted certain discrepancies between the methodology and the 

 

23 The purpose of this comparison is to note that the modeling 

analyses are actually more similar than the commenter implies. 

However, the Transport Rule differs from the commenter’s modeling due 

to the assumption that CAIR was in place. CAIR and the Transport 

Rule differ in state coverage and emission budgets. They are 

therefore not directly comparable.
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calculation of the ambient 24-hour design values. In the proposed 

rule 24-hour attainment test, for each PM2.5 monitor, we projected the 

measured 98th percentile concentrations from the 2003-2007 period to 

the future. A basic assumption in this methodology is that the 

distribution of high measured days in the base period will be the 

same in the future. For example, if the observed 98th percentile day 

is the 3rd high day for a particular year, we assume that the 1st, 

2nd, and 3rd high days (and subsequent high days) in the future 

remain in the same basic distribution. Further examination of the 

proposed rule modeling found that this is not always the case. In

situations where there are large summer PM2.5 concentration 

reductions, some of the high days may switch from the summer in the 

base period to the winter in the future period.

In order to better account for the complicated future response 

in 24-hour design values, we have updated the 24-hour attainment 

demonstration methodology to more closely reflect the way 24-hour 

design values are calculated. In the revised methodology, we do not 

assume that the temporal distribution of high days in the base and 

future periods will remain the same. We project a larger set of 

ambient days from the base period to the future and then re-rank the 

entire set of days to find the new future 98th percentile value (for 

each year). More specifically, we project the highest 8 days per 

quarter (32 days per year) to the future and then re-rank the 32 days 

to derive the future year 98th percentile concentrations. In the 

case of the Transport Rule model results, this has the effect of 
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lowering the future year 24-hour design values compared to the old 

methodology. The 2012 base case design values for all nonattainment 

and maintenance receptors were either unchanged or lower with the 

revised methodology. 

3. How did EPA project future nonattainment and maintenance for 

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

Final Rule: In general, the methodology to project ozone and 

PM2.5 concentrations to the future year(s) remains the same for the 

final rule. The proposal modeling followed the modeling guidance 

procedures for projecting ambient design values to future years. For 

the final rule, we continue to follow the basic procedures outlined 

in the guidance. The 8-hour ozone and annual PM2.5 methodology are 

unchanged from the proposal. However, the 24-hour PM2.5 methodology 

has been updated in the final rule to be more consistent with the 

calculation of 24-hour PM2.5 design values. There were also 

additional minor updates to the ambient data.

24 The methodology to 

identify maintenance receptors is also unchanged from the proposal. 

We continue to use the maximum design value (projected from the 5

year base period) to calculate future year maintenance receptors.

As noted in the proposal, 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 

 

24 The base year design values were updated based on the latest 

official data. See http://www.epa.gov/airtrends/values.html.
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variability (as discussed in detail here) directly affects the 

requirements of this final rule. EPA also considered whether further 

reductions were necessary to ensure continued lack of interference 

with maintenance of the NAAQS over time (e.g., after 2014). EPA 

concluded that in light of projected emission trends, and also 

considering the emission reductions from this proposed rule, no 

further reductions are required solely for this purpose at PM2.5 and 

ozone receptors for which we are partially or fully determining 

significant contribution for the current NAAQS. (See discussion of 

emission trends in Chapter 7 of TSD entitled ‘‘Emission 

Inventories,’’ included in the docket for the Transport Rule 

proposal.)

a. Which ambient ozone and PM2.5 data did EPA use for the purpose 

of projecting future year concentrations?

The final rule modeling continues to use a 2005 base case 

inventory and 2005 meteorology. Therefore, we continue to use 

ambient data from the 2003-2007 period. For each 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 value. The 5-year weighted average 

values were then projected to the future years that were analyzed for 

this final rule. The 2003–2005, 2004-2006, and 2005-2007 design 
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values are accessible at www.epa.gov/airtrends/values.html. The 

design values have been updated based on the latest official values. 

The official values have exceptional events removed from the 

calculations if they are flagged by states and concurred with by EPA 

Regional offices.

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

ozone conform to the methodology in the current attainment 

demonstration modeling guidance25. 

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

and Maintenance

(1) Methodology for Projecting Future Annual PM2.5 Nonattainment and 

Maintenance

For the final rule, 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 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. 

Concentrations of PM2.5 in 2012 were estimated by applying the 

modeled 2005-to-2012 relative change in PM2.5 species to each of the 

3-year ambient monitoring data periods (i.e., 2003-2005, 2004-2006, 

and 2005-2007) to obtain up to 3 future-year PM2.5 design values for 

 

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

for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, 

and Regional Haze; Office of Air Quality Planning and Standards, 

Research Triangle Park, NC.
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each monitoring site. We used the highest of these projections at 

each monitoring site to determine which sites are expected to have 

maintenance problems in 2012. We used the 5 year weighted average of 

those projections to determine which monitoring sites are expected to 

be nonattainment in this future year. 

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.26 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 722 sites 

which met this criterion for the 24-hour NAAQS.

27

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. 

EPA’s Modeled Attainment Test Software (MATS) was used to calculate 

the future year design values. The software (including 

documentation) is available at:

http://www.epa.gov/scram001/modelingapps_mats.htm. Additional

details on the annual PM2.5 nonattainment and maintenance projections

methodology can be found in the Air Quality Modeling Final Rule TSD.

 

26 If there is only one complete design value, then the nonattainment 

and maintenance design values are the same.

27 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.
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The 2012 annual PM2.5 design values were calculated for each of 

the 721 sites. The calculated annual PM2.5 design values are 

truncated after the second decimal place.

28 This is consistent with 

the ambient monitoring data 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/m

3 and is considered to be violating 

the NAAQS. Thus, sites with projected 5-year weighted average 

(“average”) annual PM2.5 design values of 15.05 μg/m3 or greater are 

predicted to be nonattainment sites. Sites with projected 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 

 

28 For example, a calculated annual average concentration of 14.94753... 

becomes 14.94 when digits beyond two places to the right of the 

decimal are truncated.
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contribution of emissions in upwind states to downwind nonattainment 

and maintenance of the annual PM2.5 NAAQS.

Table V.C-1 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 V.C-2 contains 

this same information for projected 2012 maintenance sites.

Table V.C-1. 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

Final 

Rule 

Average 

Design 

Value 

2012

Final 

Rule 

Maximum 

Design 

Value 

2012

010730023 Alabama Jefferson 18.57 18.94 16.15 16.46

010732003 Alabama Jefferson 17.15 17.69 15.16 15.64

131210039 Georgia Fulton 17.43 17.47 15.07 15.10

171191007 Illinois Madison 16.72 17.01 15.46 15.73

261630033 Michigan Wayne 17.50 18.16 15.73 16.32

390350038 Ohio Cuyahoga 17.37 18.10 15.99 16.66

390350045 Ohio Cuyahoga 16.47 16.98 15.14 15.61

390350060 Ohio Cuyahoga 17.11 17.66 15.67 16.18

390610014 Ohio Hamilton 17.29 17.53 15.76 15.98

390610042 Ohio Hamilton 16.85 17.25 15.40 15.77

390618001 Ohio Hamilton 17.54 17.90 16.01 16.33

420030064 Pennsylvania Allegheny 20.31 20.75 17.94 18.33
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Table V.C-2. Average and Maximum 2003-2007 and 2012 Base Case Annual 

PM2.5 Design Values (μg/m3) at Projected Maintenance-Only Sites

Monitor ID State County Average 

Design 

Value 

2003-

2007

Maximum 

Design 

Value 

2003-

2007

Final 

Rule 

Average 

Design 

Value 

2012

Final 

Rule 

Maximum 

Design 

Value 

2012

180970081 Indiana Marion 16.05 16.36 14.86 15.16

180970083 Indiana Marion 15.90 16.27 14.71 15.06

390350065 Ohio Cuyahoga 15.97 16.44 14.67 15.10

390617001 Ohio Hamilton 16.17 16.56 14.74 15.10

(2) Methodology for Projecting Future 24-Hour PM2.5 Nonattainment and 

Maintenance

The procedures for calculating the future year 24-hour PM2.5

design values have been updated for the final rule.

29 The revised 

procedures are in response to comments which noted relatively high 

future year 24-hour PM2.5 design values in EPA’s modeling of the 

proposed Transport Rule. The updates are intended to make the 

projection methodology more consistent with the procedures for 

calculating ambient design values. 

As noted above, for the proposed Transport Rule EPA projected 

for each PM2.5 monitor the measured 98th percentile concentrations 

from the 2003-2007 period to the future. As an additional check, we 

also projected the next highest concentrations from the three 

calendar quarters in each year when the 98th percentile did not occur 

 

29 There were no updates to the ozone and annual PM2.5 attainment test 

methodology.
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in the 2003-2007 base period, to ensure that the future year 98th 

percentile did not switch seasons in the future year compared to the 

base year. A basic assumption in this methodology is that the 

distribution of high measured days in the base period will be the 

same in the future.

In other words, EPA assumed at proposal that the 98th-percentile 

day could only be displaced “from below” in the instance that a 

different day’s future concentration exceeded the original 98thpercentile day’s future concentration. In that case, the original 

98th-percentile day may become the 97th- or 96th-percentile day in 

the future year; EPA accounted for this possibility at proposal. EPA 

did not, however, consider that the 98th-percentile day could also be 

displaced “from above” in the instance that higher-concentration days 

in the base period were projected to have future concentrations lower 

than the original 98th-percentile day’s future concentration. In 

that case, the original 98th-percentile day may become the 99th-or 

100th percentile day. Because EPA continued to use that day’s future 

concentration to determine the monitor’s future design value at 

proposal, this sometimes resulted in overstatement of future-year 

design values for 24-hour PM2.5 monitoring sites whose seasonal 

distribution of highest-concentration 24-hour PM2.5 days changed 

between the 2003-2007 period and the future year modeling. 

Examination of the proposed rule remedy modeling (2014 remedy case) 

showed that many of the highest PM2.5 days switched from the summer in 

the base period to the winter in the future period. This is 
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especially true in areas of the upper Midwest which experience both 

high summer and winter PM2.5 episodes. 

In the revised methodology, we do not assume that the seasonal 

distribution of high days in the base period years and future years 

will remain the same. We project a larger set of ambient days from 

the base period to the future and then re-rank the entire set of days 

to find the new future 98th percentile value (for each year). More 

specifically, we project the highest 8 days per quarter (32 days per 

year) to the future and then re-rank the 32 days to derive the future 

year 98th percentile concentrations. In the case of the Transport 

Rule model results, this has the effect of lowering the future year 

24-hour design values compared to the old methodology. 

The modeling guidance recommendations for state attainment 

demonstrations have been updated to reflect the changes outlined 

above. Further details on the 24-hour PM2.5 design value calculations 

can be found in the Air Quality Modeling Final Rule TSD. The above 

procedures for determining future year 24-hour PM2.5 concentrations 

were applied for each site. The 24-hour PM2.5 design values are 

truncated after the first decimal place. This approach is consistent 

with the ambient data 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 
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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. 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 final rule.

Table V.C-3 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 V.C-4 contains this same 

information for projected 2012 24-hour maintenance sites.

Table V.C-3. 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

Final 

Rule

Average 

Design 

Value 

2012

Final 

Rule

Maximum 

Design 

Value 

2012

010730023 Alabama Jefferson 44.0 44.2 36.9 37.3

170311016 Illinois Cook 43.0 46.3 37.5 40.4

171191007 Illinois Madison 39.1 40.1 36.5 36.8

180970043 Indiana Marion 38.4 39.9 35.7 37.1

180970066 Indiana Marion 38.3 39.6 35.7 36.9

180970081 Indiana Marion 38.2 39.2 35.8 36.9
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261470005 Michigan St Clair 39.6 40.6 36.2 37.1

261630015 Michigan Wayne 40.1 40.6 35.5 36.0

261630016 Michigan Wayne 42.9 45.4 38.9 41.2

261630019 Michigan Wayne 40.9 41.4 37.3 37.8

261630033 Michigan Wayne 43.8 44.2 39.4 39.8

390350038 Ohio Cuyahoga 44.2 47.0 39.4 41.8

390350060 Ohio Cuyahoga 42.1 45.7 37.7 40.8

420030064 Pennsylvania Allegheny 64.2 68.2 56.7 59.9

420030093 Pennsylvania Allegheny 45.6 51.5 39.1 44.3

420030116 Pennsylvania Allegheny 42.5 42.5 35.5 35.5

420070014 Pennsylvania Beaver 43.4 44.6 36.2 37.4

420710007 Pennsylvania Lancaster 40.8 44.0 35.9 38.3

540090011

West 

Virginia Brooke 43.9 44.9 37.5 38.3

550790043 Wisconsin Milwaukee 39.9 40.8 36.2 37.1

Table V.C-4. 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

Final 

Rule

Average 

Design 

Value 

2012

Final 

Rule

Maximum 

Design 

Value 

2012

010732003 Alabama Jefferson 40.3 40.8 35.3 35.9

170310052 Illinois Cook 40.2 41.4 34.9 36.0

170312001 Illinois Cook 37.7 40.6 33.6 36.1

170313301 Illinois Cook 40.2 43.3 34.9 37.6

170316005 Illinois Cook 39.1 41.8 34.1 36.4

171190023 Illinois Madison 37.3 38.1 35.1 35.8
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180890022 Indiana Lake 38.9 44.0 34.9 39.5

180890026 Indiana Lake 38.4 41.3 34.0 37.0

261610008 Michigan Washtenaw 39.4 40.8 35.0 36.3

390170003 Ohio Butler 39.2 41.1 34.4 36.5

390350045 Ohio Cuyahoga 38.5 41.5 34.7 38.1

390350065 Ohio Cuyahoga 38.6 41.0 34.9 37.6

390618001 Ohio Hamilton 40.6 40.9 35.2 35.8

390811001 Ohio Jefferson 41.9 45.5 34.5 37.8

391130032 Ohio Montgomery 37.8 40.0 33.6 35.6

420031008 Pennsylvania Allegheny 41.3 42.8 35.0 36.3

420031301 Pennsylvania Allegheny 40.3 42.4 33.9 35.6

420033007 Pennsylvania Allegheny 37.5 43.1 32.3 37.3

421330008 Pennsylvania York 38.2 40.7 33.3 36.0

550790010 Wisconsin Milwaukee 38.6 40.0 35.4 36.7

550790026 Wisconsin Milwaukee 37.3 41.3 33.6 37.2

(3) Methodology for Projecting Future 8-Hour Ozone Nonattainment and 

Maintenance

The final rule methodology to calculate 8-hour ozone 

nonattainment and maintenance receptors is identical to the proposed 

rule. The May-to-September 24-hour maximum 8-hour average 

concentrations from the 2005 base case and the 2012 base case were 

used to project ambient design values to 2012. The following is a 

brief summary of the future year 8-hour average ozone calculations. 

Additional details are provided in the Air Quality Modeling Final 

Rule TSD.
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We are using the base period 2003-2007 ambient ozone design 

value data for projecting future year design values. Relative 

response factors (RRF) for each monitoring site were calculated as 

the percent change in ozone on days with modeled ozone greater than 

85 ppb.

30

The maximum future design value is calculated 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 future year design values are truncated to integers in units 

of ppb. This approach is consistent with the ambient data 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 

 

30 As specified in the attainment demonstration modeling guidance, if 

there are less than 10 modeled days > 85 ppb, then the threshold is 

lowered in 1 ppb increments (to as low as 70 ppb) until there are 10 

days. If there are less than 5 days > 70 ppb, then an RRF 

calculation is not completed for that site.
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equal to the 5-year weighted average. The monitoring sites that we 

project to be nonattainment and/or maintenance for the 8-hour 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.

Table V.C-5 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 V.C-6 contains this same 

information for projected 2012 8-hour ozone maintenance sites.

Table V.C-5. 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

Final 

Rule

Average 

Design 

Value 

2012

Final 

Rule 

Maximum 

Design 

Value 

2012

220330003 Louisiana

East 

Baton Rouge 92.0 96 85.6 89.3

480391004 Texas Brazoria 94.7 97 86.7 88.8

482010051 Texas Harris 93.0 98 86.1 90.8

482010055 Texas Harris 100.7 103 93.3 95.4

482010062 Texas Harris 95.7 99 88.8 91.8

482010066 Texas Harris 92.3 96 87.1 90.6

482011039 Texas Harris 96.3 100 88.8 92.2

Table V.C-6. 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 Maximum Average Maximum 
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Design

Value 

2003-2007

Design 

Value 

2003-2007

Design 

Value 

2012

Design 

Value 

2012

090011123 Connecticut Fairfield 92.3 94 83.9 85.5

090093002 Connecticut New Haven 90.3 93 82.7 85.1

240251001 Maryland Harford 92.7 94 84.4 85.6

260050003 Michigan Allegan 90.0 93 82.4 85.1

482010024 Texas Harris 88.0 92 83.4 87.2

482010029 Texas Harris 91.7 93 84.2 85.4

482011015 Texas Harris 89.0 96 82.4 88.9

482011035 Texas Harris 86.3 95 79.9 88.0

482011050 Texas Harris 89.3 92 82.8 85.4

D. Pollution Transport from Upwind States 

1. Choice of Air Quality Thresholds

a. Thresholds

In this action, EPA uses air quality thresholds to identify 

linkages between upwind states and downwind nonattainment and 

maintenance receptors. States whose contributions to a specific 

receptor meet or exceed the thresholds identified are considered 

linked to that receptor; those states’ emissions (and available 

emission reductions) are analyzed further in the second step of EPA’s 

significant contribution analysis. States whose contributions are 

below the thresholds are not included in the Transport Rule for that 

NAAQS. In other words, we are finding that states whose 

contributions are below these thresholds do not significantly 
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contribute to nonattainment or interfere with maintenance of the 

relevant NAAQS.

We use separate air quality thresholds for annual PM2.5, 24-hour 

PM2.5, and 8-hour ozone. Each air quality threshold is calculated as 

1 percent of the NAAQS. Specifically, we use an air quality 

threshold of 0.15 μg/m3 for annual PM2.5, 0.35 μg/m3 for 24-hour PM2.5, 

and 0.8 ppb for 8-hour ozone. These are the same air quality 

thresholds we proposed.

EPA received a number of comments on the thresholds we proposed, 

and those comments and EPA’s responses are discussed below.

b. General Comments on the Overall Stringency and Use of 1 

Percent of the NAAQS.

EPA received numerous comments supporting and opposing the 

proposed thresholds. A number of commenters cited support for EPA’s 

approach. Some commenters believed that use of a 1 percent threshold 

was too stringent, and recommended that EPA should use a threshold 

greater than 1 percent. Others believed that 1 percent was not 

stringent enough, and they recommended using a lower value such as 

0.5 percent. EPA believes that for both PM2.5 and for ozone, it is 

appropriate to use a threshold of 1 percent of the NAAQS for 

identifying states whose contributions do not significantly 

contribute to nonattainment or interfere with maintenance of the 

relevant NAAQS; therefore, EPA has retained the 1 percent threshold 

for the reasons described below.
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As we found at the time of 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. (See section II of the January 

2004 CAIR proposal, 69 FR 4575-87). 

In the 1998 NOX SIP Call (63 FR 57456, October 27, 1998) and in 

CAIR, EPA also found important contributions from multiple upwind 

states. As a result of the upwind “collective contributions,” EPA 

determined that it is appropriate to use a low air quality threshold 

when analyzing upwind states’ contributions to downwind states’ 

attainment and maintenance problems for ozone as well as PM2.5. 

Low threshold values are also warranted, as EPA discussed in the 

notices for CAIR, due to adverse health impacts associated with 

ambient PM2.5 and ozone even at low concentrations (See relevant 

portions of the CAIR proposal notice (63 FR 4583-84) and the CAIR 

final rule notice (70 FR 25189-25192)).

To aid in responding to comments, EPA has compiled the

contribution modeling results to analyze the impact of different 

possible thresholds. This analysis demonstrates the reasonableness 

of using the 1 percent threshold to account for the combined impact 

of relatively small contributions from many upwind states (see Air 

Quality Modeling Final Rule TSD). In this analysis, EPA identifies 

for annual PM2.5 (sulfate and nitrate), 24-hour PM2.5 (sulfate and 
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nitrate), and 8-hour ozone receptors: (1) total upwind state 

contributions, and (2) the amount of the total upwind state 

contribution that is captured at thresholds of 1 percent, 5 percent 

and 0.5 percent of the NAAQS. EPA continues to find that the total 

“collective contribution” from upwind sources represents a large 

portion of PM2.5 and ozone at downwind locations and that the total 

amount of transport is composed of the individual contribution from 

numerous upwind States.

The analysis shows that the 1 percent threshold captures a high 

percentage of the total pollution transport affecting downwind states 

for both PM2.5 and ozone. In response to commenters who advocated a 

higher threshold, EPA observes that higher thresholds would exclude 

increasingly large percentages of total transport, which we do not 

believe would be appropriate. For example, a 5 percent threshold 

would exclude the majority -– and for annual PM, more than 80 percent 

-- of interstate pollution transport affecting the downwind state 

receptors analyzed (based on the average percentage of total 

interstate transport across all receptors captured at the 5 percent

threshold).

In response to commenters who advocated a lower threshold, EPA 

observes that the analysis shows that a lower threshold such as 0.5

percent would result in relatively modest increases in the overall 

percentages of PM2.5 and ozone pollution transport captured relative 

to the amounts captured at the 1 percent level. A 0.5 percent

threshold could lead to emission reduction responsibilities in
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additional states that individually have a very small impact on those 

receptors – an indicator that emission controls in those states are 

likely to have a smaller air quality impact at the downwind receptor. 

We are not convinced that selecting a threshold below 1 percent is 

necessary or desirable. A strong indication that the amount of 

pollution transport being excluded from consideration is not 

excessive is that the controls required under this rule are projected 

to eliminate nonattainment and maintenance problems with air quality 

standards at most downwind state receptors.

Considering the combined downwind impact of multiple upwind 

states, the health effects of low levels of PM2.5 and ozone pollution, 

and EPA’s previous use of a 1 percent threshold for PM2.5 in CAIR, 

EPA’s judgment is that the 1 percent threshold is a reasonable 

choice. 

 Some commenters noted that the PM2.5 thresholds used for this 

rule are less than the “significant impact levels” (SILs) used for 

permitting programs. As EPA stated at the time of CAIR, since the 

thresholds referred to by the commenters serve different purposes 

than the CAIR threshold for significant contribution, it does not 

follow that they should be made equivalent (70 FR 25101; May 12, 

2005).

c. Comments on the Rounding Conventions for PM2.5.

In the final Transport Rule, EPA is using two-digit values for 

the PM2.5 thresholds. Some commenters suggested that EPA should use 

the same rounding convention for annual PM2.5 used in CAIR; that is, 
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the threshold should be 0.2 μg/m3 rather than 0.15 μg/m3. The reasons 

for EPA’s decision are below.

 The rationale for the single digit value for the final CAIR rule 

was that a single digit is consistent with the EPA monitoring data 

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

reporting requirements specify that design values for the annual PM2.5

standard shall be rounded to the tenths place (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.

The reporting requirements in section Part 50, Appendix N, 

section 4.3 for the 24-hour PM2.5 standard state that design values for 

this standard 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).

If the approach used in CAIR were to be used to establish an air 

quality threshold for the 24-hour PM2.5 NAAQS (which CAIR did not 

address), the resulting threshold would be zero. One percent of the 

24-hour standard is 0.35 μg/m3, and rounding to the nearest whole 

number would yield an air quality threshold of zero. Thus if we were 

to apply the same rationale used to develop the annual PM2.5 threshold 
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for the final CAIR, there would be no air quality threshold for 24-

hour PM2.5, which EPA believes to be counter-intuitive and unworkable 

as an approach for assessing interstate contributions.

Therefore, for this rule, EPA proposed and is now finalizing an

approach that decouples the precision of the air quality thresholds 

from the monitoring reporting requirements, and uses 2-digit values 

representing one percent of the PM2.5 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 and would automatically adjust the 

stringency of the transport threshold to maintain a constant 

relationship with the stringency of the relevant NAAQS as they are 

revised. The CAIR approach would not allow for this continuity: 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 the same outcome: 0.1 

μg/m3. This would occur because any value less than 0.15 μg/m3 would 

round to 0.1 μg/m3 (assuming EPA would not round down to zero for the 

reasons described above), which means that the air quality threshold 

would have a different relative stringency to each possible future 

NAAQS value. For the above reasons, EPA believes the use of twodigit thresholds for both annual PM2.5 and 24-hour PM2.5 in the final 

rule is both reasonable and appropriate. The departure from the 
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approach used for annual PM2.5 in CAIR is appropriate given the 

additional considerations that were not in existence at the time of 

the final CAIR, and the importance of using a consistent approach to 

developing air quality thresholds for all NAAQS addressed by this 

rule as well as future NAAQS considered in future transport-related 

actions.

Some of these commenters suggested using the CAIR rounding 

conventions coupled with use of a 1-digit threshold of 0.4 μg/m3 for 

24-hour PM2.5. EPA considered the approach suggested by commenters, 

but determined that the proposed approach is more appropriate. 

First, adhering to the rounding conventions used for CAIR for annual 

PM2.5 is not workable for the 24-hour standard because the rounding 

convention would yield a threshold of zero. Rounding alternatively 

to 0.4 μg/m3 would require EPA to find a basis for rounding the 

threshold to the nearest 0.1 μg/m3 instead of using a strict 

application of 1 percent; we do not see any basis for such rounding 

at this time.

d. Comments Related to the Multi-Factor Test EPA Used for Ozone 

in CAIR.

Some commenters suggested that, for ozone, EPA should use the 

multiple-metric test we used for CAIR, and not a simple threshold 

based on 1 percent of the NAAQS. With respect to ozone, EPA proposed 

in the Transport Rule to take a more straightforward approach to air 

quality thresholds than the multi-factor approaches used for the NOX

SIP Call and the CAIR. As proposed, EPA is using a contribution 
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metric that is calculated based on the multi-day average 

contribution. This metric is compared to one percent of the 1997 8-

hour ozone standard of 0.08 ppm. Under this approach, one percent of 

the NAAQS is a value of 0.8 ppb. Contributions of 0.8 ppb and higher 

are above the threshold; ozone contributions less than 0.8 ppb are 

below the threshold. In past rulemakings (e.g., CAIR) EPA used 

multiple ozone metrics, including the average contribution and 

maximum single day contribution to downwind nonattainment. EPA 

believes the average contribution (calculated over multiple high 

ozone days) is a robust metric compared to the maximum contribution 

on a single day. EPA believes that this approach is preferable 

because it uses a robust metric, it is consistent with the approach 

for PM2.5, and it provides for a consistent approach that takes into 

account, and is applicable to, any future ozone standards below 0.08 

ppm.

One of these commenters suggested that the 0.8 ppb threshold 

value was substantially more stringent than the 2 ppb screening test 

which was a part of the approach used for CAIR. The 1 percent 

threshold (0.8 ppb) is not substantially more stringent than the 

previous 2 ppb test because of differences in the metrics used to 

evaluate contributions against these two levels. The 2 ppb test was 

evaluated using the highest single day absolute model-predicted 

downwind contribution from an upwind state. The 1 percent threshold 

is evaluated based on the average relative downwind impact calculated 

over multiple days. Therefore, it is appropriate to set a lower 
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concentration threshold for use with the average contribution metric 

calculated for the Transport Rule. More details on the calculation of 

the contribution metric can be found in the Air Quality Modeling 

Final Rule TSD. As noted above, EPA believes that the approach used 

for the proposed rule provides for a simplified, yet robust approach 

compared to CAIR. Accordingly, for the final rule we have retained 

the approach used for the proposal.

One commenter suggested that EPA retain the CAIR multiple-factor 

approach for ozone, and to apply that same approach to 24-hour PM2.5. 

As noted above, EPA is not retaining this approach for ozone, and for 

similar reasons we believe a multi-factor approach is not needed for 

24-hour PM2.5. The approach based on 1 percent of the NAAQS is 

consistent with the form of the 24-hour standard. In addition, this 

approach is based on contributions on days with high 24-hour PM2.5

predictions and therefore is relevant for characterizing transport 

during short-term high PM2.5 episodic conditions.

e. Comments on the Relationship to Measurement Precision.

Other commenters suggested that, as did commenters on the 

thresholds used in CAIR, EPA should take into consideration the 

measurement precision of existing PM2.5 monitors in setting the 

thresholds for the Transport Rule. EPA disagrees that monitoring 

precision is relevant to determining the amount of modeled PM2.5 or 

ozone that should be considered to be a “contribution” from upwind 

states since states are not required to, nor would it be possible for 

them to, measure their individual state impacts on downwind 
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receptors. The approach for eliminating significant contribution is 

based on the implementation of enforceable emissions budgets and not 

on a measurement of ambient air quality. Thus, EPA believes it is a 

reasonable exercise of its discretion to de-couple monitoring 

precision from the choice of contribution states. 

f. Comments Related to the CAIR Court Decision. 

Commenters recommended that EPA should have retained the 

criteria used for CAIR because those values were upheld by the Court. 

As noted above, EPA could not have used the approach for annual PM2.5

that was used in CAIR to develop a 24-hour PM2.5 threshold, as that 

approach would have yielded a threshold value of zero 24-hour PM2.5. 

Further, nothing in the North Carolina opinion suggests that the 

thresholds and methods used in CAIR were the only possible approaches 

EPA could have used, that they were preferable to other approaches, 

or that other alternatives would not be acceptable. Instead, the 

Court upheld the 0.2 μg/m3 threshold used for PM2.5 on the grounds that 

it was not “wholly unsupported by the record” (North Carolina, 531 

F.3d at 915). EPA has determined for reasons explained in the record 

that the thresholds used in this final rule are both reasonable and 

appropriate for use in this final rule.

2. Approach for Identifying Contributing Upwind States

This section documents the procedures used by EPA to quantify 

the contribution of emissions in specific upwind states to air 

quality concentrations in projected 2012 downwind nonattainment and 

maintenance locations for annual PM2.5, 24-hour PM2.5, and 8-hour 
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ozone. In the proposed rule 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. In this 

modeling we tracked the ozone and PM2.5 formed from 2012 base case 

emissions from anthropogenic sources in each upwind state in the 12 

km modeling domain. The CAMx Particulate Source Apportionment 

Technique (PSAT) was used to calculate downwind contributions to 

nonattainment and maintenance of PM2.5. 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 V.A, the nitrate and sulfate contributions were combined and 

used to evaluate interstate contributions of PM2.5.

The CAMx Ozone Source Apportionment Technique (OSAT) was used to 

calculate downwind 8-hour ozone contributions to nonattainment and 

maintenance. OSAT tracks the formation of ozone from NOX and VOC 

emissions. 

Comment: Three commenters stated that the CAMx source 

apportionment techniques used for the proposed rule reflect state-ofthe science technologies and are appropriate for evaluating 

interstate transport. One commenter asked that EPA do more to 

demonstrate that the PSAT and OSAT techniques give reliable answers, 

although no suggestions were provided on how this might be done. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Another commenter said that the results of the contribution analyses

were consistent with the results of their scientific research. 

Response: EPA is not changing its conclusion that the CAMx 

source apportionment techniques are appropriate for quantifying 

interstate transport. The strength of the source apportionment 

technique is that all modeled ozone and/or PM2.5 mass at a given 

location in the modeling domain is tracked back to specific sources 

of emissions and boundary conditions to fully characterize culpable 

sources. No commenters provided technically valid analyses 

indicating that EPA’s use of CAMx source apportionment techniques are 

inappropriate for the purposes of the Transport Rule.

Comment: We received comments that certain states included in 

the proposed rule should be excluded from the final rule because EPA 

had overstated the 2012 emissions in these states. Commenter 

requested that we redo the contribution modeling using 2012 base case 

emission inventories that are revised based on proposed rule 

comments. Several commenters also asked that EPA update the 

contribution modeling analyses using the latest version of CAMx. 

Response: In response to these comments, we have rerun our 

source apportionment modeling for PM2.5 and ozone for the 2012 base 

case using the updated emission inventories described above in 

section V.C.1 and the latest version of CAMx, version 5.30.

The states EPA analyzed for interstate contributions for ozone 

and for PM2.5 for the final rule are: Alabama, Arkansas, Connecticut, 

Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, 
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Kentucky, Louisiana, Maine, Maryland,

31 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.

32 These are 

the same states that EPA analyzed for the proposed rule. 

For the proposed rule, we used a relative approach for 

calculating the contributions to downwind nonattainment and 

maintenance receptors from the outputs of the source apportionment 

modeling. As part of this approach, the source apportionment 

predictions are combined with measurement-based concentrations to 

calculate the contributions from each state to nonattainment and/or 

maintenance receptors. This is similar to the approach used to 

calculate future year design values, as described in section V.C.2. 

Comment: One commenter said that using the source apportionment 

modeling predictions in a relative sense strengthens the 

determination of contributions and addresses an important source of 

 

31 As in the proposal, EPA has combined the contributions from Maryland and 

the District of Columbia as a single entity in our contribution analysis for 

the final rule. EPA believes that this is a fair representation of 

emissions for transport analysis because of the small size of the District 

of Columbia and its close proximity to Maryland. However, the District of 

Columbia is not included in the Transport Rule due to the significant 

contribution analysis findings in section VI.D.

32 There were also several other states that are only partially contained 

within the 12 km modeling domain (i.e., Colorado, Montana, New Mexico, and 

Wyoming). However, EPA did not individually track the emissions or assess 

the contribution from emissions in these states. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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uncertainty. There were no comments that suggested an alternative 

approach.

Response: For the final Transport Rule we are applying the 

relative approach developed for the proposed rule to calculate 

contributions from each state to downwind nonattainment and 

maintenance receptors.

As noted above, for the final rule we modeled the updated 2012 

base case emissions using CAMx v5.30 to determine the contributions 

from emissions in upwind states to nonattainment and maintenance 

sites in downwind states. Contributions to nonattainment and 

maintenance receptors are evaluated independently for each state to 

determine if the contributions are at or above the threshold 

criteria. 

For each upwind state, the maximum contribution to nonattainment 

is calculated based on the single largest contribution to a future 

year (2012) downwind nonattainment receptor. The maximum 

contribution to maintenance is calculated based on the single largest 

contribution to a future year (2012) downwind maintenance receptor. 

Since the contributions are calculated independently for each 

receptor, the upwind contribution to maintenance can sometimes be 

larger than the contribution to nonattainment, and vice versa. This 

also means 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.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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V.D.2.a. Estimated interstate contributions to annual PM2.5 and 24-

hour PM2.5

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 and the 24-hour PM2.5 NAAQS based on 

modeling updated for the final rule. As described previously in 

section V.D.1, states which contribute 0.15 μg/m3 or more to annual 

PM2.5 nonattainment or maintenance in another state are identified as 

states with contributions 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 nonattainment and 

maintenance sites large enough to warrant further analysis. 

For annual PM2.5, we calculated each state’s contribution to each 

of the 12 monitoring sites that are projected to be nonattainment and 

each of the 4 sites that are projected to have maintenance problems 

for the annual PM2.5 NAAQS in the 2012 base case. A detailed 

description of the calculations can be found in the Air Quality 

Modeling Final Rule TSD. The largest contribution from each state to 

annual PM2.5 nonattainment in downwind sites is provided in Table V.D1. The Largest Contribution from Each State to Annual PM2.5

maintenance in downwind sites is also provided in Table V.D-1. The 

contributions from each state to all projected 2012 nonattainment and 

maintenance sites for the annual PM2.5 NAAQS are provided in the Air 

Quality Modeling Final Rule TSD.
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Table V.D-1. 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 0.51 0.19

Arkansas 0.10 0.04

Connecticut 0.00 0.00

Delaware 0.00 0.00

Florida 0.08 0.01

Georgia 0.46 0.13

Illinois 0.50 0.65

Indiana 1.34 1.27

Iowa 0.26 0.14

Kansas 0.09 0.04

Kentucky 0.94 0.81

Louisiana 0.09 0.03

Maine 0.00 0.00

Maryland 0.15 0.06

Massachusetts 0.00 0.00

Michigan 0.64 0.64

Minnesota 0.14 0.09

Mississippi 0.05 0.01

Missouri 1.22 0.27

Nebraska 0.06 0.03

New Hampshire 0.00 0.00

New Jersey 0.02 0.01

New York 0.21 0.21

North Carolina 0.20 0.06

North Dakota 0.06 0.04

Ohio 1.34 0.94

Oklahoma 0.08 0.03

Pennsylvania 0.54 0.54

Rhode Island 0.00 0.00

South Carolina 0.24 0.04

South Dakota 0.03 0.01

Tennessee 0.32 0.32
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Upwind State

Largest Downwind

Contribution to 

Nonattainment

for Annual PM2.5 (μg/m3)

Largest Downwind 

Contribution to 

Maintenance

for Annual PM2.5 (μg/m3)

Texas 0.18 0.07

Vermont 0.00 0.00

Virginia 0.12 0.06

West Virginia 0.95 0.40

Wisconsin 0.22 0.19

Based on the state-by-state contribution analysis, there are 18 

states33 which contribute 0.15 μg/m3 or more to downwind annual PM2.5

nonattainment. These states are: Alabama, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Maryland, Michigan, Missouri, New York, 

North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 

West Virginia, and Wisconsin. In Table V.D-2, 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 12 states which contribute 0.15 μg/m3 or more to 

downwind annual PM2.5 maintenance. These states are: Alabama, 

Illinois, Indiana, Kentucky, Michigan, Missouri, New York, Ohio, 

Pennsylvania, Tennessee, West Virginia, and Wisconsin. In Table V.D3, we provide a list of the downwind maintenance sites to which each 

 

33 As in the proposal, EPA has combined the contributions from Maryland and 

the District of Columbia as a single entity in our contribution analysis

for the final rule. EPA believes that this is a fair representation of 

emissions for transport analysis because of the small size of the District 

of Columbia and its close proximity to Maryland. However, the District of 

Columbia is not included in the Transport Rule due to the significant 

contribution analysis findings in section VI.D.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 146 of 1293

upwind state contributes 0.15 μg/m3 or more (i.e., the upwind state to 

downwind maintenance “linkages”). 

Table V.D-2. Upwind State to Downwind Nonattainment Site “Linkages” 

for Annual PM2.5

Upwind State Downwind Receptor Sites

Alabama

Fulton, GA 

(131210039)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

Georgia

Jefferson, AL 

(10730023)

Jefferson, AL 

(10732003)

Illinois

Jefferson, AL 

(10732003)

Fulton, GA 

(131210039)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

Allegheny, PA 

(420030064)

Indiana

Jefferson, AL 

(10730023)

Jefferson, AL 

(10732003)

Fulton, GA 

(131210039)

Madison, IL 

(171191007)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

Allegheny, PA 

(420030064)

Iowa

Madison, IL 

(171191007)

Kentucky

Jefferson, AL 

(10730023)

Jefferson, AL 

(10732003)

Fulton, GA 

(131210039)

Madison, IL 

(171191007)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

Allegheny, PA 

(420030064)

Maryland

Allegheny, PA 

(420030064)

Michigan

Madison, IL 

(171191007)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

Allegheny, PA 

(420030064)
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Upwind State Downwind Receptor Sites

Missouri

Madison, IL 

(171191007)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

New York

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Allegheny, PA 

(420030064)

North Carolina

Fulton, GA 

(131210039)

Ohio

Jefferson, AL 

(10730023)

Jefferson, AL 

(10732003)

Fulton, GA 

(131210039)

Madison, IL 

(171191007)

Wayne, MI 

(261630033)

Allegheny, PA 

(420030064)

Pennsylvania

Fulton, GA 

(131210039)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

South Carolina

Fulton, GA 

(131210039)

Tennessee

Jefferson, AL 

(10730023)

Jefferson, AL 

(10732003)

Fulton, GA 

(131210039)

Madison, IL 

(171191007)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

Texas

Madison, IL 

(171191007)

West Virginia

Fulton, GA 

(131210039)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390610042)

Hamilton, OH 

(390618001)

Allegheny, PA 

(420030064)

Wisconsin

Madison, IL 

(171191007)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350060)

Hamilton, OH 

(390610014)

Hamilton, OH 

(390618001)
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Table V.D-3. Upwind State to Downwind Maintenance Site “Linkages” 

for Annual PM2.5

Upwind State Downwind Receptor Sites

Alabama

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Hamilton, OH 

(390617001)

Illinois

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

Indiana

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

Kentucky

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

Michigan

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

Missouri

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

New York

Cuyahoga, OH 

(390350065)

Ohio

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Pennsylvania

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

Tennessee

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Hamilton, OH 

(390617001)

West Virginia

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

Wisconsin

Marion, IN 

(180970081)

Marion, IN 

(180970083)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390617001)

For 24-hour PM2.5, we calculated each state’s contribution to 

each of the 20 monitoring sites that are projected to be 

nonattainment and each of the 21 sites that are projected to have 

maintenance problems for the 24-hour PM2.5 NAAQS in the 2012 base 

case. A detailed description of the calculations can be found in the 

Air Quality Modeling Final Rule TSD. The largest contribution from 

each state to 24-hour PM2.5 nonattainment in downwind sites is 

provided in Table V.D-4. The largest contribution from each state to 
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24-hour PM2.5 maintenance in downwind sites is also provided in Table 

V.D-4. The contributions from each state to all projected 2012 

nonattainment and maintenance sites for the 24-hour PM2.5 NAAQS are 

provided in the Air Quality Modeling Final Rule TSD.

Table V.D-4. 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 0.51 0.42

Arkansas 0.24 0.23

Connecticut 0.10 0.18

Delaware 0.22 0.20

Florida 0.07 0.03

Georgia 1.10 0.92

Illinois 3.72 5.70

Indiana 3.56 5.15

Iowa 0.82 1.55

Kansas 0.37 0.81

Kentucky 4.38 3.58

Louisiana 0.11 0.13

Maine 0.06 0.10

Maryland 2.83 2.11

Massachusetts 0.19 0.30

Michigan 1.86 2.03

Minnesota 0.61 1.01

Mississippi 0.06 0.07

Missouri 3.73 3.71

Nebraska 0.24 0.52

New Hampshire 0.05 0.10

New Jersey 0.68 0.75

New York 0.83 1.34

North Carolina 0.40 0.38

North Dakota 0.21 0.33
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State Largest Downwind

Contribution to 

Largest Downwind 

Contribution to 

Ohio 5.85 4.74

Oklahoma 0.17 0.20

Pennsylvania 2.85 2.29

Rhode Island 0.02 0.03

South Carolina 0.29 0.25

South Dakota 0.10 0.17

Tennessee 1.38 1.30

Texas 0.37 0.33

Vermont 0.03 0.05

Virginia 1.21 1.01

West Virginia 4.02 3.33

Wisconsin 0.69 0.97

Based on the state-by-state contribution analysis, there are 21 

states34 which contribute 0.35 μg/m3 or more to downwind 24-hour PM2.5

nonattainment. These states are: Alabama, Georgia, Illinois, 

Indiana, Iowa, Kansas, Kentucky, Maryland, Michigan, Minnesota, 

Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, 

Tennessee, Texas, Virginia, West Virginia, and Wisconsin. In Table 

V.D-5, 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 21 states which contribute 0.35 μg/m3 or more to 

downwind 24-hour PM2.5 maintenance. These states are: Alabama, 

 

34 As in the proposal, EPA has combined the contributions from Maryland and 

the District of Columbia as a single entity in our contribution analysis for 

the final rule. EPA believes that this is a fair representation of 

emissions for transport analysis because of the small size of the District 

of Columbia and its close proximity to Maryland. However, the District of 

Columbia is not included in the Transport Rule due to the significant 

contribution analysis findings in section VI.D.
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Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, 

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

Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and 

Wisconsin. In Table V.D-6, 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”). 

Table V.D-5. Upwind State to Downwind Nonattainment Site “Linkages” 

for 24-hour PM2.5

Upwind State Downwind Receptor Sites

Alabama

Marion, IN 

(180970043)

Marion, IN 

(180970066)

Marion, IN 

(180970081)

Georgia

Jefferson, AL 

(10730023)

Illinois

Marion, IN 

(180970043)

Marion, IN 

(180970066)

Marion, IN 

(180970081)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350060)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030093)

Allegheny, PA 

(420030116)

Beaver, PA 

(420070014)

Brooke, WV 

(540090011)

Milwaukee, WI 

(550790043)

Indiana

Jefferson, AL 

(10730023)

Cook, IL 

(170311016)

Madison, IL 

(171191007)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350060)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030093)

Allegheny, PA 

(420030116)

Beaver, PA 

(420070014)

Brooke, WV 

(540090011)

Milwaukee, WI 

(550790043)

Iowa

Cook, IL 

(170311016)

Madison, IL 

(171191007)

Milwaukee, WI 

(550790043)

Kansas

Madison, IL 

(171191007)
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Upwind State Downwind Receptor Sites

Kentucky

Jefferson, AL 

(10730023)

Cook, IL 

(170311016)

Madison, IL 

(171191007)

Marion, IN 

(180970043)

Marion, IN 

(180970066)

Marion, IN 

(180970081)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350060)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030093)

Allegheny, PA 

(420030116)

Beaver, PA 

(420070014)

Brooke, WV 

(540090011)

Milwaukee, WI 

(550790043)

Maryland

Cuyahoga, OH 

(390350038)

Lancaster, PA 

(420710007)

Michigan

Cook, IL 

(170311016)

Madison, IL 

(171191007)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350060)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030093)

Beaver, PA 

(420070014)

Brooke, WV 

(540090011)

Milwaukee, WI 

(550790043)

Minnesota

Milwaukee, WI 

(550790043)

Missouri

Cook, IL 

(170311016)

Madison, IL 

(171191007)

Marion, IN 

(180970043)

Marion, IN 

(180970066)

Marion, IN 

(180970081)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030116)

Beaver, PA 

(420070014)

Milwaukee, WI 

(550790043)

New Jersey

Lancaster, PA 

(420710007)

New York

St Clair, MI 

(261470005)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350060)

Lancaster, PA 

(420710007)

North 

Carolina

Lancaster, PA 

(420710007)

Ohio Jefferson, AL 

(10730023)

Cook, IL 

(170311016)

Madison, IL 

(171191007)

Marion, IN 

(180970043)
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Upwind State Downwind Receptor Sites

Marion, IN 

(180970066)

Marion, IN 

(180970081)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030093)

Allegheny, PA 

(420030116)

Beaver, PA 

(420070014)

Lancaster, PA 

(420710007)

Brooke, WV 

(540090011)

Milwaukee, WI 

(550790043)

Pennsylvania

Jefferson, AL 

(10730023)

Cook, IL 

(170311016)

Madison, IL 

(171191007)

Marion, IN 

(180970043)

Marion, IN 

(180970066)

Marion, IN 

(180970081)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350060)

Brooke, WV 

(540090011)

Milwaukee, WI 

(550790043)

Tennessee

Jefferson, AL 

(10730023)

Madison, IL 

(171191007)

Marion, IN 

(180970043)

Marion, IN 

(180970066)

Marion, IN 

(180970081)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Allegheny, PA 

(420030116)

Texas

Madison, IL 

(171191007)

Virginia

Lancaster, PA 

(420710007)

West Virginia

Jefferson, AL 

(10730023)

Cook, IL 

(170311016)

Madison, IL 

(171191007)

Marion, IN 

(180970043)

Marion, IN 

(180970066)

Marion, IN 

(180970081)

St Clair, MI 

(261470005)

Wayne, MI 

(261630015)

Wayne, MI 

(261630016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Cuyahoga, OH 

(390350038)

Cuyahoga, OH 

(390350060)

Allegheny, PA 

(420030064)

Allegheny, PA 

(420030093)

Allegheny, PA 

(420030116)

Beaver, PA 

(420070014)

Lancaster, PA 

(420710007)

Milwaukee, WI 

(550790043)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State Downwind Receptor Sites

Wisconsin

Cook, IL 

(170311016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)

Table V.D-6. Upwind State to Downwind Maintenance Site “Linkages” 

for 24-hour PM2.5

Upwind State Downwind Receptor Sites

Alabama

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Montgomery, OH 

(391130032)

Georgia

Jefferson, AL 

(10732003)

Illinois

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390618001)

Jefferson, OH 

(390811001)

Montgomery, OH 

(391130032)

Allegheny, PA 

(420031008)

Allegheny, PA 

(420031301)

Allegheny, PA 

(420033007)

York, PA 

(421330008)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Indiana

Jefferson, AL 

(10732003)

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Madison, IL 

(171190023)

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390618001)

Jefferson, OH 

(390811001)

Montgomery, OH 

(391130032)

Allegheny, PA 

(420031008)

Allegheny, PA

(420031301)

Allegheny, PA 

(420033007)

York, PA 

(421330008)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Iowa

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Madison, IL 

(171190023)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State Downwind Receptor Sites

Kansas

Cook, IL 

(170310052)

Cook, IL 

(170316005)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Kentucky

Jefferson, AL 

(10732003)

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Madison, IL 

(171190023)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390618001)

Jefferson, OH 

(390811001)

Montgomery, OH 

(391130032)

Allegheny, PA 

(420031008)

Allegheny, PA 

(420031301)

Allegheny, PA 

(420033007)

York, PA 

(421330008)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Maryland

York, PA 

(421330008)

Michigan

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Madison, IL 

(171190023)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Butler, OH 

(390170003)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390618001)

Jefferson, OH 

(390811001)

Montgomery, OH 

(391130032)

Allegheny, PA 

(420031008)

Allegheny, PA 

(420031301)

Allegheny, PA 

(420033007)

York, PA 

(421330008)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Minnesota

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Missouri

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Madison, IL 

(171190023)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Hamilton, OH 

(390618001)

Montgomery, OH 

(391130032)

Allegheny, PA 

(420031008)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State Downwind Receptor Sites

Nebraska

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

New Jersey

York, PA 

(421330008)

New York

Washtenaw, MI 

(261610008)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350065)

York, PA 

(421330008)

North 

Carolina

York, PA 

(421330008)

Ohio

Jefferson, AL 

(10732003)

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Madison, IL 

(171190023)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Washtenaw, MI 

(261610008)

Allegheny, PA 

(420031008)

Allegheny, PA 

(420031301)

Allegheny, PA 

(420033007)

York, PA 

(421330008)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Pennsylvania

Jefferson, AL 

(10732003)

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Madison, IL 

(171190023)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390618001)

Jefferson, OH 

(390811001)

Montgomery, OH 

(391130032)

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)

Tennessee

Jefferson, AL 

(10732003)

Madison, IL 

(171190023)

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390618001)

Montgomery, OH 

(391130032)

Virginia

York, PA 

(421330008)

West Virginia

Jefferson, AL 

(10732003)

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Madison, IL 

(171190023)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

Washtenaw, MI 

(261610008)

Butler, OH 

(390170003)

Cuyahoga, OH 

(390350045)

Cuyahoga, OH 

(390350065)

Hamilton, OH 

(390618001)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State Downwind Receptor Sites

Jefferson, OH 

(390811001)

Montgomery, OH 

(391130032)

Allegheny, PA 

(420031008)

Allegheny, PA 

(420031301)

Allegheny, PA 

(420033007)

York, PA 

(421330008)

Milwaukee, WI 

(550790010)

Wisconsin

Cook, IL 

(170310052)

Cook, IL 

(170312001)

Cook, IL 

(170313301)

Cook, IL 

(170316005)

Lake, IN 

(180890022)

Lake, IN 

(180890026)

b. Estimated Interstate Contributions to 8-Hour Ozone

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 V.D.1, 

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 calculated each state’s contribution to ozone at each of the 

4 monitoring sites that are projected to be nonattainment and each of 

6

35 sites that are projected to have maintenance problems for the 8-

hour ozone NAAQS in the 2012 base case. A detailed description of 

the calculations can be found in the Air Quality Modeling Final Rule 

TSD. The largest contribution from each state to 8-hour ozone 

 

35 There are 6 additional sites with projected 2012 nonattainment or 

maintenance (Harris Co., Texas sites 482010024, 482010062, 482010066, 

482011015, 482011035, and 482011039) for which there are less than 5 days 

with 8-hour ozone predictions of at least 70 ppb. Thus, we did not 

calculate contributions for these 6 sites.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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nonattainment in downwind sites is provided in Table V.D-7. The 

largest contribution from each state to 8-hour ozone maintenance in 

downwind sites is also provided in Table V.D.2-7. The contributions 

from each state to all projected 2012 nonattainment and maintenance 

sites for the 8-hour ozone NAAQS are provided in the Air Quality 

Modeling Final Rule TSD. 

Table V.D-7. 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 4.0 2.8

Arkansas 2.1 2.0

Connecticut 0.0 0.2

Delaware 0.0 0.6

Florida 0.5 3.6

Georgia 1.6 2.8

Illinois 1.9 26.8

Indiana 1.3 9.4

Iowa 0.6 0.9

Kansas 0.5 1.0

Kentucky 1.6 1.6

Louisiana 8.0 11.1

Maine 0.0 0.0

Maryland 0.0 3.4

Massachusetts 0.0 0.6

Michigan 0.0 0.9

Minnesota 0.3 0.2

Mississippi 4.0 3.3

Missouri 1.1 4.8

Nebraska 0.2 0.2

New Hampshire 0.0 0.1
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State

Largest Downwind

Contribution to 

Largest Downwind 

Contribution to 

New Jersey 0.0 11.5

New York 0.0 18.8

North Carolina 0.5 1.3

North Dakota 0.2 0.1

Ohio 0.1 3.2

Oklahoma 0.3 2.8

Pennsylvania 0.1 8.2

Rhode Island 0.0 0.0

South Carolina 0.4 0.9

South Dakota 0.1 0.1

Tennessee 2.2 1.1

Texas 3.9 1.9

Vermont 0.0 0.0

Virginia 0.2 8.2

West Virginia 0.0 2.8

Wisconsin 0.2 2.2

Based on the state-by-state contribution analysis, there are 11 

states that contribute 0.8 ppb or more to downwind 8-hour ozone 

nonattainment. These states are: Alabama, Arkansas, Georgia, 

Illinois, Indiana, Kentucky, Louisiana, Mississippi, Missouri, 

Tennessee, and Texas.36 In Table V.D-8, 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”).

 

36 As discussed in section III, EPA is issuing a supplemental notice 

of proposed rulemaking to provide an opportunity for public comment 

on our conclusion that emissions from Iowa, Kansas, Michigan, 

Missouri, Oklahoma, and Wisconsin significantly contribute to 

nonattainment or interfere with maintenance of the 1997 ozone NAAQS 

in other states.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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There are 26 states37 which contribute 0.8 ppb or more to 

downwind 8-hour ozone maintenance. These states are: Alabama, 

Arkansas, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, New 

Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin.38 

In Table V.D.2-9, 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 V.D-8. Upwind State to Downwind Nonattainment “Linkages” for 

8-hour Ozone

Upwind State Downwind Receptor Sites

Alabama

East Baton 

Rouge, LA 

(220330003)

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Arkansas

East Baton 

Rouge, LA 

(220330003)

Brazoria, TX 

(480391004)

 

37 As in the proposal, EPA has combined the contributions from 

Maryland and the District of Columbia as a single entity in our 

contribution analysis for the final rule. EPA believes that this is 

a fair representation of emissions for transport analysis because of 

the small size of the District of Columbia and its close proximity to 

Maryland. However, the District of Columbia is not included in the 

Transport Rule due to the significant contribution analysis findings 

in section VI.D.

38 As discussed in section III, EPA is issuing a supplemental notice 

of proposed rulemaking to provide an opportunity for public comment 

on our conclusion that emissions from Iowa, Kansas, Michigan, 

Missouri, Oklahoma, and Wisconsin significantly contribute to 

nonattainment or interfere with maintenance of the 1997 ozone NAAQS 

in other states.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State Downwind Receptor Sites

Georgia

East Baton 

Rouge, LA 

(220330003)

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Illinois

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Indiana

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Kentucky

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Louisiana

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Mississippi

East Baton 

Rouge, LA 

(220330003)

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Missouri

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Tennessee

East Baton 

Rouge, LA 

(220330003)

Brazoria, TX 

(480391004)

Harris, TX 

(482010051)

Harris, TX 

(482010055)

Texas

East Baton 

Rouge, LA 

(220330003)

Table V.D-9. Upwind State to Downwind Maintenance “Linkages” for 8-

Hour Ozone

Upwind State Downwind Receptor Sites

Alabama

Harris, TX 

(482010029)

Harris, TX 

(482011050)

Arkansas

Allegan, MI 

(260050003)

Florida

Harris, TX 

(482010029)

Harris, TX 

(482011050)

Georgia

Harris, TX 

(482010029)

Harris, TX 

(482011050)

Illinois

Fairfield, CT 

(90011123)

Allegan, MI 

(260050003)

Harris, TX 

(482011050)

Indiana

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

Allegan, MI 

(260050003)

Iowa

Allegan, MI 

(260050003)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Upwind State Downwind Receptor Sites

Kansas

Allegan, MI 

(260050003)

Kentucky

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

Harris, TX 

(482011050)

Louisiana

Harris, TX 

(482010029)

Harris, TX 

(482011050)

Maryland

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Michigan

Harford, MD 

(240251001)

Mississippi

Harris, TX 

(482010029)

Harris, TX 

(482011050)

Missouri

Allegan, MI 

(260050003)

New Jersey

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

New York

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

North Carolina

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

Ohio

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

Oklahoma

Allegan, MI 

(260050003)

Pennsylvania

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

South Carolina

Harris, TX 

(482010029)

Tennessee

Fairfield, CT 

(90011123)

Harford, MD 

(240251001)

Harris, TX 

(482011050)

Texas

Allegan, MI 

(260050003)

Virginia

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

West Virginia

Fairfield, CT 

(90011123)

New Haven, CT 

(90093002)

Harford, MD 

(240251001)

Wisconsin

Allegan, MI 

(260050003)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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VI. Quantification of State Emission Reductions Required

A. Cost and Air Quality Structure for Defining Reductions

1. Summary

Section V, above, describes EPA’s approach to identifying upwind 

states with air quality contributions that meet or exceed the air 

quality thresholds discussed therein for each of the NAAQS addressed 

in this rule. A state is covered by the Transport Rule if its 

contributions meet or exceed one of those air quality thresholds and 

the Agency identifies, using the cost- and air quality-based approach 

described below, emissions within the state that constitute the 

state’s significant contribution to nonattainment and interference 

with maintenance with respect to the 1997 ozone, 1997 PM2.5 or 2006 

PM2.5 NAAQS.

In this section, EPA explains its final cost- and air qualitybased approach to quantify the amount of emissions that represent 

significant contribution to nonattainment and interference with 

maintenance for each state. EPA then applies that approach for the 

three different NAAQS being addressed in this rule: the 1997 ozone 

NAAQS, the 1997 annual PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS. 

EPA believes that the methodology finalized could also be used to 

address transport concerns under other NAAQS, including future 

revisions to the ozone and PM2.5 NAAQS.

EPA applies the methodology described herein to fully quantify 

the emissions that constitute each covered state’s significant 

contribution to nonattainment and interference with maintenance with 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 164 of 1293

respect to the 1997 annual PM2.5 and the 2006 24-hour PM2.5 NAAQS. The 

FIPs with respect to the annual and 24-hour PM2.5 NAAQS that are 

finalized in this action ensure that all such emissions are 

prohibited. Each such FIP thus fully satisfies the requirements of 

110(a)(2)(D)(i)(I) with respect to the annual and/or 24-hour PM2.5

NAAQS for the covered state.

EPA also applies the methodology to quantify significant 

contribution to nonattainment and interference with maintenance with 

respect to the 1997 ozone NAAQS. However, we have not been able to 

fully quantify such emissions for all covered states. In this 

action, EPA fully quantifies the significant contribution to 

nonattainment and interference with maintenance for 15 states. We 

finalize FIPs with respect to the 1997 ozone standards for 10 of 

these 15 states (Florida, Maryland, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South Carolina, Virginia, and West 

Virginia). We are also publishing a supplemental notice of 

rulemaking to take comment on whether FIPs should be finalized for 

the remaining 5 states (Iowa, Kansas, Michigan, Oklahoma, and 

Wisconsin). The FIPs for these 10 states (and the FIPs for the 

remaining 5 states, if finalized) fully satisfy the requirements of 

110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS for the 

covered state.

In addition, we apply the methodology described herein to 

quantify, for 11 additional states, ozone-season NOX emission 

reductions that are necessary but may not be sufficient to eliminate 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 165 of 1293

all significant contribution to nonattainment and interference with 

maintenance in other states. We finalize FIPs with respect to the 

1997 ozone standards for 10 of these 11 states (Alabama, Arkansas, 

Georgia, Illinois, Indiana, Kentucky, Louisiana, Mississippi, 

Tennessee, and Texas). We are also publishing a supplemental notice 

of rulemaking to take comment on whether FIPs should be finalized for 

the remaining state (Missouri). The FIPs for these 10 states (and 

the FIP for the remaining state, if finalized) make measurable 

progress toward satisfying the requirements of 110(a)(2)(D)(i)(I) 

with respect to the 1997 ozone NAAQS in each covered state. To the 

extent that significant contribution to nonattainment and 

interference with maintenance is not entirely eliminated for the 1997 

ozone NAAQS through today’s action, EPA will address these instances 

in a future rulemaking. This is further explained in section VI.D.

With respect to the 1997 annual PM2.5 NAAQS, this rule finds that 

18 states have SO2 and NOX emission reduction responsibilities. EPA 

also finds that 21 states have SO2 and NOX emission reduction 

responsibilities with respect to the 2006 24-hour PM2.5 NAAQS. There 

are a total of 23 states that have SO2 and NOX emission reduction 

responsibilities for one or both of the above PM2.5 NAAQS. We apply 

the methodology to quantify emission reductions that these states 

must achieve to eliminate the state’s significant contribution to 

nonattainment and interference with maintenance. The states are 

listed in Table III-1 in section III of this preamble.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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This rule will prohibit all significant contribution to 

nonattainment and interference with maintenance with respect to the 

annual and 24-hour PM2.5. In addition, it will resolve air quality 

issues at most nonattainment and maintenance receptors identified by 

EPA. EPA projects that unresolved nonattainment and maintenance 

issues will remain in only a few downwind states after promulgation 

and implementation of the Transport Rule. For the annual PM2.5

standard, EPA projects that this rule will help assure that all areas 

in the east fully resolve their nonattainment and maintenance 

concerns. This rule will also help a number of areas achieve the 

standard earlier than they may have otherwise. For the 2006 24-hour 

PM2.5 NAAQS, one area is projected to remain in nonattainment 

(Liberty-Clairton) and three areas are projected to have remaining 

maintenance concerns after imposition of the Transport Rule 

(Chicago,39 Detroit, and Lancaster County).40

The methodology provides similar assistance for ozone, assuring 

upwind reductions that will assist downwind states in controlling 

ozone pollution. It reduces ozone concentration levels in 2012 and 

helps assure that all but two downwind areas fully resolve their 

 

39 This area is not currently designated as nonattainment for the 24-

hour PM2.5 standard. EPA is portraying the receptors and counties in 

this area as a single 24-hour maintenance area based on the annual 

PM2.5 nonattainment designation of Chicago-Gary-Lake County, IL-IN.

40 In the Transport Rule proposal, EPA noted that the Liberty-Clairton 

receptor in Allegheny county was significantly impacted by local 

emissions from a sizeable coke production facility and other nearby 

sources (75 FR 45281).
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nonattainment and maintenance problems with the 1997 ozone NAAQS by 

2014. While Houston is projected to still face nonattainment and 

Baton Rouge is projected to still face maintenance concerns with the 

1997 ozone NAAQS, the Transport Rule improves air quality in these 

two areas and provides both health benefits and assistance for these 

local areas in meeting the NAAQS requirements. For reasons explained 

below, EPA will conduct further analysis in a subsequent transportrelated rulemaking to determine whether further upwind state 

reductions are warranted to assist attainment and maintenance of the 

ozone NAAQS in Houston and Baton Rouge areas.

When EPA proposed this air-quality and cost-based multi-factor 

approach to identify emissions that constitute significant

contribution to nonattainment and interference with maintenance from 

upwind states with respect to the 1997 ozone, annual PM2.5, and 2006 

24-hour PM2.5 NAAQS, the Agency indicated that the approach was 

designed to be applicable to both current and potential future ozone 

and PM2.5 NAAQS (75 FR 45214). EPA believes that the final Transport 

Rule demonstrates the value of this approach for addressing the role 

of interstate transport of air pollution in communities’ ability to 

comply with current and future NAAQS. EPA believes that the 

Transport Rule's approach of using air-quality thresholds to 

determine upwind-to-downwind-state linkages and using the cost- and 

air quality-based multi-factor approach to quantify significant 

contribution to nonattainment and interference with maintenance 

(i.e., to determine the specific amount of emissions that each upwind 
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state must reduce) could serve as a precedent for quantifying upwind 

state emission reduction responsibilities with respect to potential 

future NAAQS.

One commenter suggested that the rule could set a flawed 

precedent for future transport analyses and remedies, as it does not 

fully eliminate the prohibited emissions in every upwind state. EPA 

disagrees with this characterization of the Transport Rule. EPA 

notes that the partial determination of significant contribution to 

nonattainment and interference with maintenance for certain upwind 

states in the Transport Rule with respect to the ozone NAAQS is not a 

function of the multi-factor approach itself, but is instead a 

function of its limited application in this rulemaking to identify 

emission reductions from a single source category (EGUs). In fact, 

the Transport Rule's approach itself allowed EPA to determine for 

which upwind states we have identified all emissions that constitute 

significant contribution to nonattainment and interference with 

maintenance, and for which upwind states we have identified emissions 

that are necessary but may not be sufficient to eliminate the 

prohibited emissions. As EPA explained at proposal, developing the 

additional information needed to consider NOX emissions from non-EGU 

source categories in order to fully quantify upwind state 

responsibility with respect to the 1997 ozone NAAQS would 

substantially delay promulgation of the Transport Rule. EPA 

explained that we do not believe that effort should delay the 

emission reductions and large health benefits this final rule will 
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deliver (75 FR 45213). EPA further explained that we believe it is 

likely that the Agency can provide the greatest assistance to states 

in addressing transported pollution by issuing a separate 

(subsequent) rule to address additional reductions that may be 

necessary to fully eliminate upwind state responsibility with respect 

to the 1997 ozone NAAQS (75 FR 45288). Thus, EPA decided to 

promulgate the Transport Rule as quickly as possible. EPA 

anticipates that application of this air-quality and cost-based 

multi-factor approach to a broader set of source categories in a 

subsequent rulemaking will identify any remaining prohibited 

emissions in the upwind states for which the Transport Rule may not 

fully eliminate those emissions with respect to the 1997 ozone NAAQS.

2. Background

After using air quality analysis to identify upwind states that 

are “linked” to downwind air quality monitoring sites with 

nonattainment and maintenance problems through contribution of at 

least one percent of the relevant NAAQS, EPA quantifies the portion 

of each state’s contribution that constitutes its “significant 

contribution” or “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 to nonattainment and interference with 

maintenance with respect to the NAAQS of concern. For this portion 

of the analysis, EPA expands upon the methodology used in the NOX SIP 

Call and CAIR but modifies it in important respects. In the NOX SIP 
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Call and CAIR, EPA’s methodology defined significant contribution as 

those emissions that could be removed with the use of “highly cost 

effective” controls. In the Transport Rule, rather than relying 

solely on an analysis of what constitutes “highly cost effective” 

controls, EPA relies on an analysis that accounts for both cost and 

air quality improvement to identify the portion of a state’s 

contribution that constitutes its significant contribution to 

nonattainment and interference with maintenance. Furthermore, in 

response to the Court’s opinion in North Carolina, EPA has developed 

an approach which gives independent meaning to the “interfere with 

maintenance” prong of section 110(a)(2)(D)(i)(I). 

The methodology takes into account both the D.C. Circuit Court’s 

determination that EPA may consider cost when measuring significant 

contribution, Michigan, 213 F.3d at 679, and its rejection of the 

manner in which cost was used in the CAIR analysis, North Carolina,

531 F.3d at 917. It also recognizes that the Court accepted -- but 

did not require -- EPA’s use of a single, uniform cost threshold to 

measure significant contribution. Michigan, 213 F.3d at 679.

As EPA discussed at length in the Transport Rule proposal, 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 (75 FR 45271). 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, 
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additional emission 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 

interference with maintenance in another state. As discussed in more 

detail in the proposal, interpreting significant contribution to 

nonattainment and interference with maintenance inherently involves a 

decision on how much emissions control responsibility should be 

assigned to upwind states, and how much responsibility should be left 

to downwind states. EPA’s methodology is intended to “assign a 

substantial but reasonable amount of responsibility to upwind 

states....to control their emissions” (75 FR 45272). EPA believes 

that upwind states contributing to downwind state air quality 

degradation should bear substantial responsibility to control their 

emissions because of the plain language of the good neighbor 

provision, the health risks and control cost impacts that upwind 

emissions cause in the downwind state, and the cumulative impact in 

the downwind state of emissions from multiple upwind states, and the 

importance of achieving attainment in downwind states as 

expeditiously as practicable but no later than specific deadlines as 

required by the Act. EPA’s approach does not shift the 

responsibility for achieving or maintaining the NAAQS to the upwind 

state. See 75 FR 45272. 
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The methodology defines each state’s significant contribution to 

nonattainment and interference with maintenance as the emission 

reductions available at a particular cost threshold in a specific 

upwind state which effectively address nonattainment and maintenance 

of the relevant NAAQS in the linked downwind states of concern. 

Unlike the NOX SIP Call and CAIR, where EPA’s significant contribution 

analysis had a regional focus, the methodology used in the Transport 

Rule 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. There are four steps to this 

methodology: (1) identification of each state’s emission reductions 

available at ascending costs per ton as appropriate; (2) assessment 

of those upwind emission reductions’ downwind air quality impacts; 

(3) identification of upwind “cost thresholds” delivering effective 

emission reductions and downwind air quality improvement; and (4) 

enshrinement of the upwind emission reductions available at those 

cost thresholds in state budgets.

In step one, EPA identifies what emission reductions are 

available at various cost thresholds, quantifying emission reductions 

that would occur within each state at ascending costs per ton of 

emission reductions. In other words, EPA determined for specific 

cost per ton thresholds, the emission reductions that would be 

achieved in a state if all EGUs greater than 25 MW in that state used 
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all emission controls and emission reduction measures available at 

that cost threshold. For purposes of this discussion, we refer to 

these as “cost curves.”

For this final rule, EPA used updated IPM modeling to conduct a 

similar cost curve analysis as conducted in the Transport Rule 

proposal (75 FR 45275). In the proposal, the cost curves only 

reflected escalating cost for one pollutant while the other pollutant 

cost was held constant at base case levels (i.e., $0/ton). However, 

EPA improved the costing analysis for the final rule by identifying 

upwind emission reductions available as costs were imposed on both SO2

and NOX simultaneously for states linked to downwind states on the 

basis of the PM2.5 NAAQS. In other words, the cost curves in the 

proposal depicted state level emissions when only one pollutant was 

priced (i.e., NOX at $500/ton). Separate cost curves were done for 

each pollutant. For the final rule, EPA conducted some preliminary 

cost curve analysis for identifying NOX thresholds in this manner. 

However, for the final cost curve analysis, EPA relied on cost curves 

that reflected state emissions when pollutants were priced 

simultaneously (e.g., NOX at $500/ton and SO2 at $1,600/ton). For 

reasons described in section VI.B, EPA was able to conduct this type 

of analysis because the preliminary cost curves specific to annual 

and ozone-season NOX suggested little flexibility in adjusting the 

$500/ton cost thresholds imposed for each. Therefore, EPA was able 

to hold the cost threshold constant at $500/ton for these pollutants 

in its examination of SO2 at various cost thresholds. EPA believes 
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this approach to cost analysis is a better simulation of the 

Transport Rule’s likely impact on covered sources. Under the final 

Transport Rule, covered sources in states regulated for PM2.5 must 

address compliance requirements for SO2 and NOX emissions 

simultaneously, and this refined approach to cost curve analysis and 

subsequent air quality analysis better reflects this reality. 

Section VI.B of this preamble describes the costing analysis in 

further detail. Also, for more detail on the development of the cost 

curves, see “Significant Contribution and State Emission Budgets

Final Rule TSD” in the docket for this rule.

Although the cost curves presented in this rule only include EGU 

reductions, EPA also assessed the cost of SO2 and NOX emission 

reductions available for source categories other than EGUs in the 

proposed rulemaking. This preliminary assessment in the rule 

proposal suggested that there likely would be very large emission 

reductions available from EGUs before costs reach the point for which 

non-EGU sources have available reductions (75 FR 45272). EPA 

revisited these non-EGU reduction cost levels in this final 

rulemaking and verified that there are little or no reductions 

available from non-EGUs at costs lower than the thresholds that EPA 

has chosen ($500/ton for NOX, $2,300/ton for SO2). 

Further details on EPA’s application of cost curves are provided 

below, in section VI.B.

In step two, EPA uses an air quality assessment tool to estimate 

the impact that the combined reductions available from upwind 
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contributing states and the downwind receptor state at different 

cost-per-ton levels would have on air quality at downwind monitoring

sites projected to have nonattainment and/or maintenance problems.41 

While less rigorous than the air quality models used for attainment 

demonstrations, EPA believes this air quality assessment tool (which 

has been refined since proposal) is acceptable for assessing the 

impact of numerous options for upwind emission reductions in the 

process of defining an upwind state’s significant contribution to 

nonattainment and interference with maintenance. It allows the 

Agency to anticipate specific air quality impacts of many more 

potential emission reduction scenarios pertinent to the relevant 

NAAQS than time- and resource-intensive comprehensive air quality 

modeling would permit.

Further details on EPA’s application of step two in this 

methodology are provided below, in section VI.C. 

In step three, EPA examines cost and air quality information to 

identify “significant cost thresholds.” EPA considered a significant 

cost threshold to be a point along the cost curves where a noticeable 

 

41 As is discussed in the RIA, EPA also used the CAMx model to perform 

air quality analysis of its proposed remedy to address significant 

contribution. Results from this modeling will not exactly correspond 

to results from the air quality assessment 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.
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change occurred in downwind air quality, such as a point where large 

upwind emission reductions become available because a certain type of 

emissions control strategy becomes cost-effective.42 

This methodology allows EPA, where appropriate, to define 

multiple cost thresholds that vary for a particular pollutant for 

different upwind states. As explained in the Transport Rule 

proposal, EPA does not believe it is required to utilize multiple 

cost thresholds to regulate upwind emissions for purposes of the 

mandate in CAA section 110(a)(2)(D), but EPA’s multi-factor 

methodology developed for the Transport Rule to define significant 

contribution to nonattainment and interference with maintenance 

allows the Agency to consider whether a single cost threshold or 

multiple cost thresholds are appropriate for meeting the requirements 

of CAA section 110(a)(2)(D) relevant to a particular NAAQS (75 FR 

45274).

In step four, EPA uses the information regarding emission 

reductions available in each “linked” upwind state at the appropriate 

cost threshold to form a state “budget,” representing the remaining 

emissions from covered sources for the state in an average year once 

significant contribution to nonattainment and interference with 

maintenance have been eliminated; each budget also allows for the 

 

42 The cost thresholds identified in this rule are specific to the 

section 110(a)(2)(D)(i)(I) 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.
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identification of an associated variability limit. These budgets and 

variability limits are used to develop enforceable requirements under 

the final remedy. The final rule’s methodology for identifying state 

budgets is derived directly from the cost curves and multi-factor

analysis EPA uses to determine each state’s significant contribution 

to nonattainment and interference with maintenance. State emission 

budgets are discussed in section VI.D and the variability limits are 

discussed in section VI.E.

B. Cost of Available Emission Reductions (Step 1)

This subsection provides more detail on the cost curves that EPA 

developed to assess the costs of reducing SO2 and NOX emissions to 

address transport related to ozone and PM2.5 concentrations (described 

previously as Step 1). It summarizes the information from the curves 

and then provides EPA’s interpretation of that information. EPA used 

IPM to develop the EGU cost curves described in this rulemaking. 

More information can be found regarding EPA’s use of IPM for the 

final Transport Rule in the “Significant Contribution and State 

Emission Budgets Final Rule TSD”. 

The amount of emission reductions that the cost curves suggest 

are available at various costs are specific to the 2012 and 2014 time 

periods. These cost estimates factor in the time interval between 

rule finalization and compliance periods, existing controls already 

in place, and controls that could potentially come on line by the 

start of the compliance period. EPA notes that cost curves are a 

fluid concept and would vary given different compliance dates. 
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1. Development of Annual NOX and Ozone-Season NOX Cost Curves

EPA conducted preliminary cost curve analysis for annual NOX and 

ozone-season NOX in a similar manner to that used in the proposed 

rulemaking. That is, the impact of various cost thresholds on 

emissions was examined individually. For example, state level 

emissions were examined at cost levels for annual NOX of $500, $1,000, 

and $2,500/ton while SO2 was held at base case levels. EPA used this 

approach to examine NOX and ozone-season NOX emission reductions 

available from EGUs by 2012 and 2014 at various cost levels, reaching 

to $2,500/ton for annual NOX and up to $5,000/ton for ozone-season NOX

(in 2007-year dollars). Section VI.D explains why EPA analyzed the 

$500/ton threshold for annual and ozone-season NOX. EPA selected two 

higher cost thresholds to analyze for annual and ozone-season NOX that 

provided a reasonable spectrum of emission reduction opportunities 

from EGUs at higher cost thresholds. Specifically, EPA analyzed 

these two higher cost thresholds because the first ($1,000/ton) was 

informative in regards to the additional EGU NOX emissions reductions 

available without installation of advanced controls, and the second 

($2,500/ton for annual NOX, $5,000/ton for ozone-season NOX) was 

informative in regards to additional EGU reductions available at cost 

thresholds where advanced NOX control retrofits are economic for some 

units. The cost thresholds were only applied to states with air 

quality contributions that meet or exceed the air quality thresholds

as identified in section V.D. For both annual and ozone-season NOX, 
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EPA did not consider cost thresholds below $500/ton for reasons 

explained in section VI.D.

EPA observed in the proposal that low-cost NOX reductions are 

available at upwind sources with existing pollution control equipment 

that may not otherwise be operated in the future without the 

Transport Rule. EPA believes it is appropriate to prohibit any 

“linked” upwind state from potentially increasing its emissions 

through a failure to operate these existing pollution controls, which 

could worsen downwind air quality problems. Thus, EPA reflected 

operation of these controls in all modeling of different cost 

thresholds (i.e., the modeling assumes year-round operation of postcombustion NOX controls in covered PM2.5 states and ozone-season 

operation of post-combustion NOX controls in covered ozone states).

Table VI.B-1 shows the annual NOX emissions from EGUs at various 

levels of control cost per ton for 2014. Table VI.B-2 presents the 

cost curves for ozone-season NOX emissions from EGUs. As discussed in 

section VI.D, EPA determined that $500/ton for annual and ozone NOX

was the appropriate cost threshold for this rule (although EPA plans 

to determine in the future whether a higher cost/ton threshold may be 

warranted for states contributing to nonattainment or maintenance 

problems with the 1997 ozone air quality standard projected to remain 

in two downwind areas).

Table VI.B-1 2014 Annual NOX Emissions from Fossil-Fuel Fired EGUs 

Greater than 25 MW for Each Transport Rule State at Various Costs Per 

Ton [(2007$) Per Ton (Thousand Tons)]

Base 

Case $500 $1,000 $2,500 
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Level

Alabama

 

75 

 

72 

 

72 

 

70 

Georgia

 

48 

 

41 

 

41 

 

39 

Illinois

 

55 

 

51 

 

50 

 

49 

Indiana

 

117 

 

108 

 

107 

 

100 

Iowa

 

45 

 

40 

 

39 

 

37 

Kansas

 

32 

 

25 

 

25 

 

23 

Kentucky

 

83 

 

83 

 

81 

 

78 

Maryland

 

17 

 

17 

 

17 

 

17 

Michigan

 

64 

 

61 

 

61 

 

60 

Minnesota

 

38 

 

30 

 

30 

 

30 

Missouri

 

55 

 

54 

 

54 

 

51 

Nebraska

 

43 

 

27 

 

26 

 

21 

New Jersey

 

8 

 

8 

 

8 

 

8 

New York

 

19 

 

19 

 

18 

 

18 

North 

Carolina

 

46 

 

46 

 

46 

 

44 

Ohio

 

99 

 

95 

 

94 

 

92 

Pennsylvania

 

132 

 

124 

 

124 

 

116 

South 

Carolina

 

38 

 

38 

 

37 

 

36 

Tennessee

 

29 

 

29 

 

29 

 

29 

Texas

 

141 

 

138 

 

138 

 

136 

Virginia

 

36 

 

35 

 

35 

 

28 

West 

Virginia

 

64 

 

64 

 

64 

 

61 

Wisconsin

 

37 

 

32 

 

32 

 

31 
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Total

 

1,321 1,236 

 

1,229 

 

1,174 

Table VI.B-2 2012 Ozone-Season NOX Emissions from Fossil-Fuel Fired 

EGUs Greater than 25 MW for Each Transport Rule State at Various 

Costs [(2007$) Per Ton (Thousand Tons)]

Base case 

level $500 $1,000 $5,000

Alabama 34 34 34 31

Arkansas 15 15 15 14

Florida 42 27 27 24

Georgia 29 28 28 25

Illinois 21 21 21 21

Indiana 47 46 46 43

Kentucky 38 37 36 34

Louisiana 13 13 13 13

Maryland 7 7 7 7

Mississippi 10 10 10 9

New Jersey 3 3 3 3

New York 8 8 8 8

North 

Carolina 23 23 23 21

Ohio 42 42 42 38

Pennsylvania 53 53 52 49

South 

Carolina 15 15 15 14

Tennessee 16 16 15 15

Texas 65 63 63 60

Virginia 15 15 15 13

West 

Virginia 26 26 26 24

Total 523 504 501 467
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EPA notes that the cost curves presented here differ somewhat 

from the cost curves presented in the proposal. The NOX emissions 

modeled at a $500/ton cost threshold for the final rule are lower 

than they were at proposal. In addition, the emission reductions 

they represent from the updated base case are not as pronounced as 

was found in modeling for the proposed rule. It is worth emphasizing 

that the lower emission reductions observed at $500/ton in this final 

rulemaking are due to a lower starting point in updated base case EGU 

NOX emission levels (and thus do not reflect higher NOX emissions 

remaining after the reductions made at the $500/ton threshold). 

While the base case 2012 nationwide annual EGU NOX emissions were 

approximately 3 million tons in the proposal, they were only 2.1

million tons in the final rule. This approximately 33 percent 

reduction in base case EGU NOX emissions in the final rule modeling 

relative to the proposal is due to a combination of modeling updates, 

including lower natural gas prices, reduced electricity demand, 

newly-modeled consent decrees and state rules, and updated NOX rates 

to reflect 2009 emissions data. All of these factors resulted in 

substantially lower base case Transport Rule NOX emissions in the 

final rule modeling. 

2. Development of SO2 Cost Curves

As explained in detail below in section VI.D, EPA determined 

that a single threshold of $500/ton for ozone-season NOX control in 

the states covered for the 1997 ozone NAAQS and a single threshold of 

$500/ton for annual NOX control in the states covered for the PM2.5
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NAAQS were appropriate cost thresholds for identifying upwind control 

under the Transport Rule. With these parameters determined, EPA was 

able to assess the availability of SO2 emission reductions from EGUs 

at various SO2 cost per ton thresholds with the corresponding NOX

reduction requirements simultaneously represented in the analysis. 

This approach of simultaneously modeling cost levels for covered 

pollutants is different from the approach taken in the proposal. In 

the proposal, cost curves were developed and examined independently 

for each pollutant. For example, with the SO2 cost curves in the 

proposal, the NOX cost level was held constant at base case levels as 

the SO2 cost threshold was varied from base case levels to $2,400/ton. 

Commenters noted that this did not accurately reflect a reality where 

source owners/operators view price signals for all covered pollutants 

simultaneously and make operation decisions accordingly. For the 

final rule, EPA included cost thresholds of $500/ton for annual NOX in

PM2.5 states and $500/ton for ozone-season NOX in ozone-season states 

while examining different SO2 cost thresholds. This allows EPA to 

develop final cost curves for air quality analysis and budget 

determination that reflect EGU operation when faced with the 

appropriate cost thresholds on all covered pollutants. EPA believes 

this approach of modeling final cost curves is superior to the 

methodology used in the proposal because it reflects market signals 

for each pollutant simultaneously, as would be experienced by states 

and sources regulated under the Transport Rule. 
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In this manner, EPA examined several SO2 cost thresholds of $500, 

$1,600, $2,300, $2,800, $3,300 and $10,000 per ton. EPA selected 

these cost thresholds for the final rule's analysis as a 

representative sampling of points along the SO2 cost curve thoroughly 

explored at proposal. Modeling of these cost thresholds provided a 

spectrum of emission reduction opportunities yielding meaningful 

differences to consider in total costs and air quality improvements 

at each threshold. The proposal's more detailed analysis using 

smaller increments between cost thresholds outlined the general form 

of the sector's SO2 emission reduction cost curve and therefore 

allowed EPA to use larger increments between cost thresholds for the 

final rule's analysis. Each of the cost thresholds examined for the 

final rule represents a point where there is a significant change in 

available controls, emission reductions, or costs and economic 

impacts. EPA believes analysis of these thresholds illustrate a 

meaningful progression of costs and air quality impacts that enabled 

the Agency to determine a proper threshold along this cost curve to 

identify significant contribution to nonattainment and interference 

with maintenance for this rulemaking.

The cost thresholds above $500/ton were applied starting in 

2014. In all modeling, the 2012 cost per ton threshold was held 

constant at $500/ton as EPA believes that this cost threshold 

captures all emission reductions feasible by 2012 (see section 

VI.B.3 below for more discussion). At the higher cost levels (e.g., 

$2,800/ton and above), the curve does not include all available 
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reductions as they do not include non-EGU reductions. As described 

above for NOX, EPA also observed at proposal that substantial low-cost 

SO2 reductions are available from the operation of existing scrubbers 

that may not otherwise operate in the future without the Transport 

Rule in place. Therefore, all of the final SO2 cost curves assume 

operation of existing scrubbers in PM2.5 states under the Transport 

Rule. In 2014, approximately 3 million tons of SO2 reductions can be 

achieved at the $500/ton cost threshold through operation of existing 

controls and some fuel switching. 

This final cost curve also appropriately reflects the Group 

1/Group 2 distinction for states covered for PM2.5. As discussed in 

more detail in section VI.D, EPA identified Group 2 states as those 

that were linked to states where all nonattainment and maintenance 

issues had been resolved at $500/ton levels. There is no longer any 

significant contribution to nonattainment or interference with 

maintenance by these seven Group 2 states at levels above $500/ton. 

Therefore, in the final curves, these Group 2 states’ cost thresholds 

were held constant at $500/ton as the higher cost thresholds were 

applied to the remaining Group 1 states starting in 2014. For 

example, the modeled emissions at the $2,300 per ton cost threshold 

shown in Table VI.B-3 below reflect each state’s emissions when Group 

1 states are subjected to a $2,300 per ton SO2 constraint and Group 2 

states are subjected to a $500/ton SO2 constraint. 

Additional reductions can be achieved at the higher cost 

thresholds. The cost curves demonstrate that sources begin to build 
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significant additional flue gas desulfurization (FGD) retrofits at an 

SO2 cost threshold of $1,600 per ton and additional dry sorbent 

injection (DSI) retrofits at an SO2 cost threshold of $2,300 per ton.

With these final cost curves in hand, EPA was able to identify 

the combined reductions available from upwind contributing states and 

the downwind state, at different cost-per-ton levels. Additionally, 

EPA was able to examine the economic impacts of imposing such cost 

constraints on power sector generation. However, this only 

constitutes a portion of EPA’s multi-factor assessment used to 

determine the amount of emissions that represent significant 

contribution to nonattainment and interference with maintenance. As 

noted in the Transport Rule proposal, EPA’s multi-factor assessment 

considered air quality and cost considerations when identifying cost 

thresholds (75 FR 45271). The air quality portion of the assessment 

is described in section VI.C of the final Transport Rule preamble.

3. Amount of Reductions that Could Be Achieved by 2012 and 2014

EPA applied escalating SO2 cost per ton thresholds for Group 1 

states to create the cost curves for 2014 and beyond. For 2012 SO2, 

the cost per ton was held constant at $500/ton as the cost thresholds 

in 2014 and beyond were varied. The advanced pollution controls 

incentivized by these higher cost-per-ton levels can reasonably be 

installed by 2014. EPA also considered whether any of these emission 

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 
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2012 to ensure that they are achieved as expeditiously as 

practicable. SO2 and NOX reductions come from operating existing 

controls, installing combustion controls, fuel switching, and 

increased dispatch of lower-emitting generation which can be achieved 

by 2012. In general, compliance mechanisms that do not involve postcombustion control installation are feasible before 2014. For this 

reason, EPA believes it is appropriate to require these emissions to 

be removed in 2012, consistent with the Act’s requirement that 

downwind states attain the NAAQS as expeditiously as practicable. 

Therefore, all of the cost curves presented below include all 

feasible 2012 reductions up to a threshold of $500/ton for SO2 and 

$500/ton for annual NOX in states linked to receptors for PM2.5, as 

well as $500/ton for ozone-season NOX in states linked to receptors 

for ozone. These cost per ton levels do not precipitate advanced 

post-combustion control installation in 2012 (as EPA acknowledges 

that such installations are not feasible by 2012), but they do 

promote the compliance options outlined above. The higher cost 

thresholds for SO2 Group 1 states were only applied starting in 2014. 

Therefore, the 2012 state level emissions in the “$2,300 per ton 

threshold” reflect a cost threshold of only $500/ton for all 

pollutants (the $2,300 per ton value starts in 2014 for Group 1 

states’ SO2).

The table below illustrates the change in state level SO2

emissions as the higher cost per ton thresholds are applied to Group 

1 states. 
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Table VI.B-3 2014 SO2 Emissions from Fossil-Fuel-Fired EGUs Greater 

than 25 MW for each Transport Rule State at Various Costs Per Ton 

(Thousand Tons)

a

State

SO2

Group

Base 

Case 

Level $500 $1,600 $2,300 $2,800 $3,300 $10,000 

Alabama 2 417 201 226 213 214 236 190

Georgia 2 170 94 94 95 95 95 98

Illinois 1 138 134 130 124 117 102 36

Indiana 1 711 245 179 161 153 121 69

Iowa 1 127 112 78 75 67 45 13

Kansas 2 70 55 57 61 61 61 45

Kentucky 1 488 161 126 106 103 89 46

Maryland 1 43 32 28 28 26 24 18

Michigan 1 266 206 189 144 105 94 24

Minnesota 2 66 43 45 46 46 46 44

Missouri 1 382 212 173 166 109 84 21

Nebraska 2 72 68 70 70 70 70 66
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New Jersey 1 39 7 7 7 7 6 5

New York 1 40 21 20 12 11 10 8

North 

Carolina 1 120 104 61 58 49 40 30

Ohio 1 832 294 175 137 123 115 65

Pennsylvania 1 507 294 164 112 107 102 75

South 

Carolina 2 210 93 100 103 104 104 105

Tennessee 1 284 82 63 59 59 59 24

Texas 2 453 281 282 284 281 281 243

Virginia 1 65 59 51 35 33 32 16

West 

Virginia 1 497 157 122 76 74 72 55

Wisconsin 1 125 51 47 40 38 34 14

Total 6,122 3,007 2,487 2,212 2,053 1,919 1,311

Group 1 

total 4,665 2,172 1,612 1,340 1,180 1,025 520

Group 2 

total 1,457 835 875 872 872 894 791

aNote - As described in the preamble language for this section, the 

escalating cost per ton figures in each column header only apply to Group 1 
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states in 2014 and each year thereafter. Cost per ton for Group 2 states 

is held constant at $500/ton for all the costing runs. In some cases, the 

escalating cost levels in Group 1 states affect emission levels in Group 2 

states as some generation shifts between states in response to newly 

imposed costs.

C. Estimates of Air Quality Impacts (Step 2)

After developing cost curves to show the state-by-state costeffective emission reductions available, EPA estimates the air 

quality impacts of these reductions using the air quality assessment 

tool coupled with full-scale air quality modeling where possible. 

EPA uses the air quality assessment tool to evaluate the impact on 

air quality for downwind nonattainment and maintenance receptors from 

upwind reductions in ‘‘linked’’ states. This section describes the 

development of the air quality assessment tool and summarizes the 

results of this evaluation. 

1. Development of the Air Quality Assessment Tool and Air Quality 

Modeling Strategy

In response to comments on the methodology used for the proposed 

rule, EPA made significant improvements to the air quality assessment 

tool (AQAT) for the final Transport Rule. Furthermore, EPA relied on 

CAMx to model the air quality response to NOX reductions and limited 

AQAT’s role (relative to the Transport Rule proposal) to estimating

the relative response of sulfate concentrations from SO2 reductions. 

EPA did not use AQAT to address NOX reductions in the final rule 

analyses. These and other changes to our approach, as described 

below and in the “Significant Contribution and State Emission Budgets 
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Final Rule TSD”, address commenter’s concerns about the scientific 

rigor of the design and application of AQAT and commenter’s 

recommendations to rely upon air quality modeling as part of this 

analysis.

For the final Transport Rule, EPA created an AQAT calibration 

scenario consisting of full-scale air quality modeling using CAMx of 

a 2014 control scenario reflecting SO2 and NOX emission reductions of 

similar stringency and from the same geography as the Transport Rule 

proposal. Modeling of this AQAT calibration scenario reflected all 

updates made to the air quality modeling platform, as described in 

the “Air Quality Modeling Final Rule TSD” found in the docket for 

this rulemaking. CAMx modeling of each receptor’s response in this 

control scenario accounts for complex chemical interactions and 

covariation of these pollutants. Among the important atmospheric 

chemical interactions accounted for in CAMx is “nitrate 

replacement.”

43 Nitrate replacement occurs when SO2 emission 

reductions lead to decreases in ammonium sulfate, which in turn, can 

result in an increase in ammonium nitrate concentrations. As 

described below, EPA used the CAMx modeling results for this AQAT 

calibration scenario together with the modeling for the 2012 base 

case to characterize the response of ozone, nitrate, and sulfate at 

 

43 Observable indicators of the sensitivity of PM2.5 nitrate to

emission reductions—Part II: Sensitivity to errors in total

ammonia and total nitrate of the CMAQ-predicted non-linear

effect of SO2 emission reductions. R.L. Dennis, P.K. Bhave, and R.W. 

Pinder. 2008. Atmospheric Environment (42):1287-

1300.doi:10.1016/j.atmosenv.2007.10.036
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each nonattainment and maintenance receptor to the mix of upwind NOX

and SO2 emission reductions at each cost threshold. 

As described in section VI.D, EPA determined that the $500/ton 

threshold for upwind annual and ozone-season NOX control is 

appropriate for the final Transport Rule (although EPA plans to 

determine in the future whether a higher cost/ton threshold may be 

warranted for states contributing to nonattainment or maintenance 

problems with the 1997 ozone air quality standard projected to remain 

at receptors in two downwind areas44). Because this threshold 

corresponds to the NOX control strategy modeled in the AQAT 

calibration scenario described above, EPA is able to rely on this 

CAMx air quality modeling to assess the response of ozone and nitrate 

concentrations due to NOX reductions and does not estimate ozone or 

nitrate impacts for this final rulemaking using AQAT. Further 

information on the air quality modeling of this AQAT calibration 

scenario can be found in the Air Quality Modeling Final Rule TSD and 

the Significant Contribution and State Emission Budgets Final Rule 

TSD in the docket for this rulemaking.

In order to estimate 2014 annual and 24-hour PM2.5

concentrations, AQAT uses the 2012 annual and seasonal contributions 

which quantify the contribution of SO2 emissions in specific upwind 

states to sulfate concentrations at specific downwind receptors. 

These contributions are described in section V.D.2 and the Air 

Quality Modeling Final Rule TSD.

 

44 Houston and Baton Rouge nonattainment areas
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EPA utilizes CAMx modeling of the AQAT calibration scenario, 

described above, to “calibrate” the contribution factors by 

developing and applying linear sulfate response factors for each 

downwind receptor. These factors calibrate each receptor’s sulfate 

response to varying levels of upwind SO2 emissions. These calibration 

factors are based on the sulfate response modeled by CAMx due to 

emission changes occurring between the 2012 base case and the 2014 

AQAT calibration scenario. Calibration factors were constructed for 

the annual and 24-hour PM2.5 AQAT. 

To further allow adequate assessment of the seasonal impacts of 

various levels of upwind SO2 reductions on each receptor’s 24-hour 

PM2.5 concentration using AQAT, EPA developed response factors for 

sulfate on a quarterly basis to capture important air quality 

differences between summer and winter emissions and concentrations. 

This process allowed EPA to estimate the air quality values for each 

season at each cost threshold, and then estimate the air quality 

design values.

Finally, EPA’s air quality assessment accounts for the impact 

that this differential response in sulfate by quarter can have on the 

ordering of 24-hour concentrations when calculating the 98th 

percentile for the 24-hour standard. AQAT estimates quarterlyspecific relative response factors that estimate quarterly-specific 

proportional change in ammonium sulfate resulting from the SO2

emission reduction from the 2012 base case scenario to the 2014 cost 

threshold scenario being assessed. These quarterly relative response 
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factors are then applied to each of the maximum 24-hour PM2.5

concentrations for eight days per quarter per year at each receptor 

from the 2012 base case. This methodology improvement allows EPA to 

redetermine the 98th percentile day for each year and recalculate 

average and maximum design values for the 24-hour PM2.5 standard.

These improvements for the final rule increase EPA’s confidence 

that the air quality estimates provided by AQAT, now customized for 

this application, more accurately estimate the results of full-scale 

air quality modeling of the various levels of upwind SO2 reductions 

considered. EPA evaluated the estimates from AQAT using an 

independent data set, the 2014 base case estimates from CAMx, finding 

that the results are unbiased with minimal differences. See

“Significant Contribution and State Emission Budgets Final Rule TSD”

for more details.

As such, EPA believes the revised AQAT provides an appropriate 

basis for assessing the air quality portion of the multi-factor 

methodology to define significant contribution to nonattainment and 
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interference with maintenance.

45

2. Utilization of AQAT to Evaluate Control Scenarios

For the final Transport Rule, EPA performed air quality analysis 

for each downwind annual and 24-hour PM2.5 receptor with a 

nonattainment and/or maintenance problem in the 2012 base case. For 

each receptor, EPA quantified the sulfate reduction and resulting air 

quality improvement when a group of states consisting of the upwind 

states that are ‘‘linked’’ to the downwind receptor (as explained in 

section V.D) and the downwind state where the receptor is located, 

all made the SO2 emission reductions that EPA identified as available 

at each cost threshold. EPA assumes reductions at each cost 

threshold from the linked upwind states as well as the downwind 

receptor state to assess the shared responsibility of these upwind 

 

45 EPA used CAMx to conduct full air quality modeling of the final 

Transport Rule remedy embodying the emission reductions that EPA 

first selected on the basis of the multi-factor analysis using AQAT 

to project air quality impacts from varying levels of emission 

reductions analyzed. The CAMx results confirmed the relative 

magnitude and direction of AQAT's estimates of the outcomes for the 

2012 base case nonattainment and maintenance receptors analyzed, and 

the AQAT estimates closely tracked CAMx-modeled concentrations at 

those receptors under the Transport Rule remedy. The paired AQATestimated and CAMx-modeled concentrations were found to be highly 

correlated with an R2 value of 0.997. As a result, EPA is confident 

that AQAT's estimates of impacts on sulfate concentrations at the 

varying levels of SO2 emission reductions analyzed provide a 

technically valid and sound basis for the Agency's selection of the 

final rule's emission reductions necessary to eliminate (or make 

meaningful progress toward eliminating) significant contribution and 

interference with maintenance for the PM2.5 NAAQS considered in this 

rulemaking. Further details on the comparison of CAMx and AQAT 

results can be found in the Significant Contribution and State 

Emission Budgets Final Rule TSD.
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states to address air quality at the identified receptors. Analysis 

of each receptor did not assume any emission reductions beyond those 

included in the 2014 base case from upwind states that are not 

‘‘linked’’ to that specific downwind receptor (even if the state was 

‘‘linked’’ to a different receptor and/or otherwise would have made 

emission reductions beginning in 2012 due to the Transport Rule).

EPA disagrees with comments suggesting that emission reductions, 

and resulting decreases in contribution, from upwind states that are 

not “linked” to a particular downwind receptor should be accounted 

for in the 2014 AQAT analysis of that receptor. EPA decided to 

assume reductions only from linked states when analyzing each 

receptor because EPA is performing a state-specific analysis to 

support a determination of the amount of each upwind state’s 

responsibility for air quality problems at the downwind receptors 

that it significantly affects. If the AQAT analysis were to assume 

emissions reductions in other non-linked states, the AQAT analysis 

would then contradict the first step of our two-step approach to 

defining significant contribution to nonattainment and interference 

with maintenance. Under EPA’s two-step approach, only a state that 

(1) contributes a threshold amount or more to a particular downwind 

state receptor’s air quality problem, and (2) has emission reductions 

available at the selected cost threshold can be deemed to have 

responsibility to reduce its emissions to improve air quality at that 

downwind receptor. EPA believes that the commenters’ suggested 

approach would not qualify as a state-specific approach for 
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determining upwind state responsibility for downwind air quality 

problems. 

Because EPA is relying on the CAMx estimate of nitrate 

concentrations from the AQAT calibration scenario, the response in 

nitrate to NOX reductions at a cost threshold of $500/ton is present 

in each SO2 cost threshold scenario analyzed.

EPA determines the cumulative air quality improvement that can 

be expected at a particular downwind receptor by multiplying each 

upwind state’s percent SO2 emission reduction by its calibrated 

receptor specific sulfate response factor and summing the sulfate, 

nitrate, and other PM2.5 components (also taken from the 2014 CAMx 

AQAT calibration scenario).

3. Air Quality Assessment Results

The results of EPA’s air quality assessment of the cost 

threshold scenarios focus on air quality metrics including, but not 

limited to, average air quality improvement at receptors with 2012

base case nonattainment and maintenance exceedances and an evaluation 

of estimated receptor design values against annual and 24-hour PM2.5

standards. See “Significant Contribution and State Emission Budgets 

Final Rule TSD” for more details.

In EPA’s air quality analysis of each downwind receptor, all air 

quality improvements are measured relative to the “AQAT base case.” 

This base case reflects AQAT’s estimated PM2.5 concentrations under 

base case 2014 SO2 emissions. The AQAT base case itself is not used 

for any decision points and only serves as an appropriate starting 
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point for comparison of air quality improvements at SO2 cost 

thresholds. EPA ensures internal analytic consistency by comparing 

all air quality improvements at analyzed SO2 cost thresholds to the 

AQAT base case. 

Regarding average air quality improvement at exceeding 2012 base 

case receptors, EPA identified 41 receptors with nonattainment or 

maintenance problems in the 2012 base case. EPA assessed the 

cumulative reduction in 24-hour PM2.5 maximum design value at each 

increasing SO2 cost threshold from the maximum design value from the 

AQAT base case, and averaged the reduction across the 41 receptors. 

The results of this assessment indicate diminishing incremental 

returns to 24-hour PM2.5 maximum design value reduction as SO2 cost 

threshold levels increase. EPA finds reductions in maximum design 

value of 4.28 μg/m3 at $500; 4.98 μg/m3 at $1,600; 5.33 μg/m3 at 

$2,300; 5.46 μg/m3 at $2,800; 5.60 μg/m3 at $3,300; and 6.08 μg/m3 at 

$10,000. These results are provided in table VI.C-1. 

Table VI.C-1 Average 2014 Air Quality Improvement at Receptors with 

2012 Base Case Nonattainment and Maintenance Problems

Group 1 

State SO2

Cost Per Ton 

Threshold

Average Air 

Quality 

Improvement at 

Exceeding 

Receptors in 2012 

Base Case (μg/m3)

$500 4.28

$1,600 4.98

$2,300 5.33

$2,800 5.46

$3,300 5.60

$10,000 6.08
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Additionally, EPA evaluated the AQAT estimated 2014 average and 

maximum design values for these receptors at each cost threshold 

against the annual and 24-hour PM2.5 standards. EPA determined the 

estimated number of receptors with nonattainment or maintenance 

problems at $500/ton cost threshold of NOX and each of the cost 

threshold scenarios assessed for SO2. These results are provided in 

table VI.C-2 in terms of the number of receptors and the number of 

nonattainment areas containing these receptors.
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Table VI.C-2 Receptors with Nonattainment and/or Maintenance Exceedances of the Annual or 24-

hour PM2.5 NAAQS in 2014

SO2 Cost 

Threshold

Annual 

Nonattainment

Annual 

Nonattainment 

or Maintenance

24-hour

Nonattainment

24-hour

Nonattainment 

or Maintenance

Annual and 24-

hour

Nonattainment 

and Maintenance

Receptors Areas Receptors Areas Receptors Areas Receptors Areas Receptors Areas

$500 1 1 1 1 2 2 9 6 9 6

$1,600 1 1 1 1 2 2 8 5 8 5

$2,300 0 0 1 1 1 1 6 4 6 4

$2,800 0 0 1 1 1 1 5 4 5 4

$3,300 0 0 1 1 1 1 5 4 5 4

$10,000 0 0 1 1 1 1 3 3 3 3
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In the proposal, EPA evaluated whether the imposition of the 

rule’s upwind emission reduction requirements could cause changes in 

operation of electric generating units in states not regulated under 

the proposal. EPA recognized that such changes could lead to 

increased emissions in those states, potentially affecting whether 

they would meet or exceed the 1 percent contribution thresholds used 

to identify linkages between upwind and downwind states. Such 

shifting of emissions between states may occur because of the 

interconnected nature of the country’s energy system (including both 

the electricity grid as well as coal and natural gas supplies).

Using updated emissions and air quality information developed 

for the final rule, EPA’s IPM modeling found that of the states not 

covered in the final rule for PM2.5, Arkansas, Colorado, Louisiana, 

Montana, and Wyoming are all projected to have SO2 emission increases 

above 5,000 tons in 2014 with the rule in effect. EPA analysis shows 

the SO2 emission increases result from expected shifts to higher 

sulfur coal in these states. Using AQAT, a state-level assessment of 

these emission increases relative to the state specific contributions

to downwind receptors (where available) indicates that projected 

increases in the SO2 emissions would not increase any of these states’ 

contributions to an amount that would meet or exceed the 0.15 μg/m3 or 

0.35 μg/m3 thresholds for annual and 24-hour PM2.5, respectively. For 

this reason, EPA has determined that it is not necessary to include 

these additional states in the Transport Rule as a result of the 

effects of the rule itself on SO2 emissions in uncovered states. See
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“Significant Contribution and State Emission Budgets Final Rule TSD”

in the docket for this rulemaking for more details.

D. Multi-Factor Analysis and Determination of State Emission Budgets

EPA used the cost, emission, and air quality information 

described in the previous sections to perform its multi-factor 

analysis. By looking at different “cost thresholds” - places where 

there was a noticeable change on the cost curve because emission

reductions occur - and examining the corresponding impact on air 

quality, EPA identified the amount of emissions that represent 

significant contribution to nonattainment and interference with 

maintenance within each state. After quantifying this amount of 

emissions, EPA established state “budgets” which represent the 

remaining emissions for the state in an average year (step 4). 

For states covered by the rule for PM2.5, EPA calculated annual 

NOX and annual SO2 budgets. For states covered by the rule for ozone, 

EPA calculated ozone-season NOX budgets. This section explains the 

multi-factor assessment and how EPA used this assessment to determine 

state-specific budgets.

1. Multi-factor Analysis (Step 3)

a. Overview

As described in section VI.B, EPA examined how different cost 

thresholds impacted emissions in states with air quality 

contributions that meet or exceed specific air quality thresholds, as 

discussed in section V.D of this preamble. Section VI.C summarizes 

the estimated air quality impacts in 2014 of these emission levels at 
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downwind receptors, including estimates of their nonattainment and 

maintenance status (see “Significant Contribution and State Emission 

Budgets Final Rule TSD” for more details). From these two steps, EPA 

evaluated the interaction between upwind emissions at different cost 

levels and air quality at downwind receptors to identify “significant 

cost thresholds.” These cost thresholds are based on air quality 

considerations (such as the cost at which the air quality assessment 

analysis projects large numbers of downwind site maintenance and 

nonattainment problems would be resolved) or cost criteria (such as a 

cost where large emissions reductions occur because a particular 

technology is widely implemented at that cost). EPA examined each 

cost threshold and then used a multi-factor assessment to determine 

which serve as cost thresholds that eliminate significant 

contribution to nonattainment and interference with maintenance for 

upwind states. Air quality considerations in the assessment include, 

for example, how much air quality improvement in downwind states 

results from upwind state emission reductions at different levels; 

whether, considering upwind emission 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., whether it is a predominantly local or in-state 

problem, or whether it still contains a large upwind component). 

Cost considerations include, for example, how the cost per ton of 

emission reduction compares with the cost per ton of existing federal 

and state rules for the same pollutant; whether the cost per ton is 
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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); and what cost increase is required to 

achieve additional meaningful air quality improvement.

The specific cost per ton thresholds selected as a basis for 

identifying significant contribution to nonattainment and 

interference with maintenance in this rulemaking apply only to the 

determinations made in this rule and do not establish any precedent 

for future EPA actions under section 110(a)(2)(D)(i)(I) or any other 

section of the CAA. EPA’s selection of specific cost thresholds in 

the context of this rulemaking relies on current analyses of the cost 

of available emission reductions, the pattern of interstate linkages 

for pollution transport, and the downwind air quality impacts 

specifically related to the 1997 ozone NAAQS, the 1997 annual PM2.5

NAAQS, and the 2006 24-hour PM2.5 NAAQS. In addition and as explained 

below, the selection of the threshold for ozone-season NOX was 

influenced by the limited scope of this rule. Any or all of these 

variables used to identify specific cost thresholds are subject to 

change. Thus, EPA may use different cost thresholds in future 

actions, even if those actions relate to the same NAAQS addressed in 

this rule. 

b. Cost Thresholds Examined and Selected for Ozone-Season NOX

In the proposal, EPA examined various cost thresholds for ozone 

season NOX and identified a cost threshold with rapidly diminishing 

returns at $500/ton. EPA observed that moving beyond the $500 cost 
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threshold up to a $2,500 cost threshold would result in only minimal 

additional ozone season NOX emission reductions and would likely 

bypass less expensive non-EGU emission reduction opportunities (75 FR 

45281). EPA noted that for greater costs the curves did not include 

all available reductions as they do not include non-EGU reductions 

(75 FR 44286). In the proposal, EPA noted the timely promulgation 

and implementation of this rule is responsive to the Court’s remand 

of CAIR, will accelerate critical air quality improvement, and more 

effectively address the mandate of CAA section 110(a)(2)(D) to 

address significant contribution to nonattainment and interference 

with maintenance as expeditiously as practicable. EPA did not want 

to risk delaying air quality benefits available from EGU emission 

reductions, particularly those emission reductions which eliminate 

significant contribution to nonattainment and interference with 

maintenance for many receptors, while the Agency conducts additional 

analysis to support subsequent transport-related rulemakings 

including coverage of non-EGU sources (75 FR 45285).

EPA received comments suggesting that it consider cost 

thresholds higher than $500/ton as reductions beyond the proposed 

$500/ton cost threshold were needed to fully resolve nonattainment 

and maintenance issues in downwind states analyzed at proposal. Some 

of these comments suggested EPA should include non-EGUs as they 

consider the higher cost thresholds, others suggested EPA continue to 

exclude non-EGU sources in this rulemaking.
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In response to those comments that suggested EPA explore higher 

cost thresholds because nonattainment and maintenance was not fully 

resolved, EPA first notes that CAA section 110 (a)(2)(D)(i)(I) only 

requires the elimination of emissions that significantly contribute 

to nonattainment or interfere with maintenance of the NAAQS in other 

states. Section 110(a)(2)(D)(i)(I) focuses exclusively on the 

transport component of nonattainment and maintenance problems. 

Section 110(a)(2)(D)(i)(I) does not shift to upwind states the 

responsibility for ensuring that all areas in other states attain the 

NAAQS. As such, the mandate of section 110(a)(2)(D)(i)(I) is not to 

ensure that reductions in upwind states are sufficient to bring all 

downwind areas in to attainment, it is simply to ensure that all 

significant contribution to nonattainment and interference with 

maintenance is eliminated. Thus, the presence of residual 

nonattainment or maintenance areas does not, by itself, signify a 

failure to satisfy the requirements of 110(a)(2)(D)((i)(I).

Furthermore, as noted in section VI.A, EPA is finalizing 

coverage only for the EGU emission source-sector category in this 

rulemaking. EPA has not included non-EGU sources in this final 

rulemaking. EPA remains convinced that timely promulgation and 

implementation of this rule is responsive to the Court’s remand of 

CAIR.

To the extent that significant contribution is not eliminated 

for the 1997 ozone NAAQS standard at the $500/ton cost threshold, EPA 

is not addressing in this rulemaking whether a cost threshold greater 
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than $500/ton is justified for some upwind states and downwind 

receptors. EPA believes it can best serve these states where 

concerns persist regarding projected nonattainment or maintenance of 

the 1997 ozone NAAQS by quickly finalizing this rule and seeking 

further non-EGU reductions in subsequent rulemakings. Table VI.B-2 

illustrates the small amount of EGU reductions available as cost 

threshold increases above $500/ton. The ozone-season NOX reductions 

available in the Transport Rule states between the $500/ton and 

$1,000/ton cost thresholds amount to less than 3,000 tons. EPA 

believes that potentially substantial non-EGU ozone-season NOX

reductions become available approaching the $1,000/ton cost 

threshold. EPA emphasized this in the proposal, noting that the cost 

curves for ozone season NOX did not reflect all available reductions 

as they do not include non-EGU reductions (75 FR 45286). For these 

reasons, EPA did not consider cost thresholds greater than $500/ton. 

EPA did not consider cost thresholds below $500/ton for ozoneseason NOX. $500/ton is a reasonable threshold representing a 

significant amount of lowest-cost NOX emission reductions from EGUs, 

largely accruing from the installation of combustion controls, such 

as low-NOX burners, and constitutes a reasonable cost level for 

operation of existing NOX controls such as SCRs. EPA believes it 

would be inappropriate for a state linked to downwind nonattainment 

or maintenance areas to stop operating existing pollution control 

equipment (which would increase their emissions and contribution). 

This is increasingly likely to occur at cost thresholds lower than 
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$500/ton. Therefore, EPA did not find cost thresholds lower than 

$500/ton for ozone-season NOX to be reasonable for development of the 

Transport Rule cost curves. 

As discussed in section III of this preamble, EPA intends to 

finalize reconsideration of the March 2008 ozone NAAQS in the summer 

of 2011 and to expeditiously propose a transport-related action to 

address any necessary upwind state control responsibilities with 

respect to that reconsidered NAAQS.

c. Cost Thresholds Examined and Selected for Annual NOX

Following the assessment of the cost curves in section IV.B and 

the air quality modeling of the AQAT calibration scenario using CAMx, 

EPA identified a single cost threshold at $500/ton for annual NOX. 

Beyond requiring the year-round operation of existing post-combustion 

NOX controls and other reductions modeled at $500/ton threshold, EPA 

observed a limitation in available low-cost annual NOX reductions from 

EGUs. Approximately 7,000 tons of annual NOX reductions were 

available from EGUs between the $500/ton and the $1,000/ton cost 

thresholds (See Table VI.B.-1). Furthermore, above the $500/ton 

threshold, similar to ozone-season NOX cost curves, the annual NOX

cost curves do not include all available reductions as they do not 

include non-EGU reductions. EPA analysis suggests that while NOX

emission reductions lead to reductions in PM2.5, SO2 reductions are 

generally more cost-effective than NOX reductions at reducing PM2.5 (75 

FR 45281). In part, for these reasons, EPA’s multi-factor assessment 

suggested that the $500/ton cost threshold for annual NOX in concert 
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with the cost thresholds identified for SO2 were the appropriate cost 

thresholds for eliminating significant contribution to nonattainment 

and interference with maintenance. EPA finds in the final Transport 

Rule that the $500/ton cost threshold for annual NOX, in concert with 

the SO2 cost threshold selected below, successfully eliminates 

significant contribution to nonattainment and interference with 

maintenance for the 1997 annual PM2.5 NAAQS and the 2006 24-hour PM2.5

NAAQS in the states covered by this Rule for PM2.5.

The reasons for not considering cost thresholds lower than 

$500/ton for annual NOX are the same as those identified for not doing 

so for ozone-season NOX. In addition to its PM2.5 reduction benefits, 

annual NOX control at the $500/ton threshold can help to reduce

nitrate replacement in the atmosphere. As explained earlier, nitrate 

replacement happens when SO2 emissions reductions successfully reduce 

ammonium sulfate (a component of PM2.5) but provoke a PM2.5 rebound 

effect by freeing up additional ammonia to form ammonium nitrate 

(another component of PM2.5). 

d. Cost Thresholds Examined and Selected for SO2

EPA first assessed the downwind air quality impacts of emission 

reductions modeled at the $500/ton threshold in all states found to 

be linked to downwind sites for PM2.5 transport, as well as in the 

states hosting those downwind sites. The air quality assessment tool 

projected that those reductions do not fully resolve nonattainment 

and maintenance problems with the PM2.5 standards for certain areas to 

which the following states are linked: Illinois, Indiana, Iowa, 
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Kentucky, Maryland, Michigan, Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and 

Wisconsin. EPA proceeded to analyze available 2014 emission 

reductions at higher cost thresholds from these states, collectively 

referred to as Group 1 states for SO2 control.

For Group 2 states, the air quality assessment tool projected 

that the SO2 reductions at this first cost threshold assessed would 

resolve the nonattainment and maintenance problems for all of the 

areas to which the following states are linked: Alabama, Georgia, 

Kansas, Minnesota, Nebraska, South Carolina, and Texas. EPA thus 

finds that these states’ significant contribution is eliminated at 

the $500 per ton level in 2014; they are collectively referred to as 

Group 2 states for SO2 control. Because their significant 

contribution is eliminated at this stringency of control, EPA did not 

analyze higher cost thresholds for Group 2 states.

The states in Group 1 and Group 2 are rationally grouped 

considering air quality and cost. EPA determined that it would not 

be appropriate to assign the same cost threshold to Group 2 and Group 

1 states because a significantly lower cost threshold 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, EPA analysis indicated that the cost threshold 

needed to resolve downwind air quality problems varied only to a 

limited extent among states within Group 1 and among states within 

Group 2. It did, however, vary greatly between the Group 1 and Group 
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2 states. The ruling of the D.C. Circuit in Michigan v. EPA, 213 

F.3d 663, 679-80 (D.C. Cir. 2000), accepting EPA’s prior use of a 

transport remedy with uniform controls, supports EPA’s decision to 

use a uniform cost threshold for a group of states.

As discussed in section VI.B, the cost threshold for Group 1 

states was examined at escalating levels in 2014 (it remained at 

$500/ton for Group 2 states). EPA examined emissions at SO2 cost 

thresholds of $500, $1,600, $2,300, $2,800, $3,300, and $10,000/ton 

for Group 1 states in 2014. The higher SO2 marginal costs were only 

imposed in Transport Rule states starting in 2014, by which time the 

advanced pollution control retrofits induced at those higher cost 

thresholds could be installed. (See section VI.D.2 for EPA’s 

assessment and decisions regarding SO2 budget formation in Group 1 

states in 2014.)

EPA observed some degree of additional air quality benefit at 

downwind receptors across all of the cost thresholds examined for SO2, 

but significant air quality outcomes were achieved at the $2,300/ton 

cost threshold. The $2,300/ton threshold is projected to resolve the 

last remaining nonattainment area for the annual PM2.5 standard 

(Liberty-Clairton),46 and it also is projected to resolve the 

nonattainment and maintenance problems with the 24-hour PM2.5 standard 

 

46 AQAT results indicated that one receptor in the Liberty-Clairton 

area continued to have maintenance problems with the annual PM2.5

standard. However, final air quality modeling results (described in 

section VIII.B) indicated that this maintenance problem was resolved 

for this receptor under the final Transport Rule.
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at 1 monitor in the Detroit area and resolve the maintenance problems 

in the Cleveland area. There were significant air quality 

improvements at this level in connection with widespread deployment 

of pollution control technology, while the cost impacts remained 

reasonable.

Moving beyond $2,300/ton to the $2,800/ton and $3,300/ton 

thresholds, EPA projected notably smaller air quality improvements 

compared to those projected when moving from the $1,600/ton threshold 

to the $2,300/ton threshold. EPA also projected no ultimate change 

in the 24-hour PM2.5 attainment status of the remaining nonattainment 

area (Liberty-Clairton) or three remaining maintenance areas 

(Chicago,47 Detroit, and Lancaster).48 At the same time, the total 

program cost continued to increase by about the same interval at each 

of these thresholds as it had between the $1,600/ton and $2,300/ton 

thresholds. EPA thus observed a relatively lower cost-effectiveness 

of downwind PM2.5 control via upwind SO2 reductions beyond $2,300/ton 

for the receptors linked to Group 1 states. Table VI.D-1 and Figure 

VI.D-1 demonstrate this relationship between cost of EGU SO2 control 

 

47 This area is not currently designated as nonattainment for the 24-

hour PM2.5 standard. EPA is portraying the receptors and counties in 

this area as a single 24-hour maintenance area based on the annual 

PM2.5 nonattainment designation of Chicago-Gary-Lake County, IL-IN.

48 AQAT results indicated that two receptors in the Detroit area 

continued to have maintenance problems with the 24-hour PM2.5

standard. However, final air quality modeling results (described in 

section VIII.B) indicated that only one receptor continued to have 

maintenance problems in this area for this standard under the final 

Transport Rule.
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and downwind PM2.5 concentration impacts, showing a sustained 

diminishing of cost effectiveness beyond the $2,300/ton threshold. 

The $2,300/ton threshold in this analysis is situated at the “kneein-the-curve” area of cost-effectiveness for addressing downwind PM2.5

concentrations with SO2 reductions, beyond which point the air quality 

gains per dollar spent on additional reductions are much smaller. 

This relationship is demonstrative of the economic potency of SO2

reductions at each cost threshold to address the PM2.5 concentrations 

at linked receptors in this analysis.

Table VI.D-1 Cost-Effectiveness of Group 1 State SO2 Reductionsa

for Downwind PM2.5 Control

SO2 Cost 

Threshold

Additional 

System Cost 

Expended 

(2007$, 

billions)

Average PM2.5

Air Quality 

Improvement 

(μg/m3)

b

Air Quality CostEffectiveness 

(average μg/m3 

reduced per billion 

$ expended)

$500 0.22 3.27 14.74

$1,600 0.82 3.86 4.70

$2,300 1.35 4.22 3.11

$2,800 1.94 4.37 2.25

$3,300 2.36 4.50 1.91

$10,000 3.61 4.99 1.38

aDownwind PM2.5 improvement based on SO2 reductions from states 

“linked” to specific receptors. See section VI.C.

bMeasured as the reduction in maximum design value for the 24-hour 

PM2.5 NAAQS from AQAT base case to each SO2 threshold for receptors 

with remaining nonattainment and maintenance exceedances at the 

$500/ton threshold, averaged across these receptors. 

Figure VI.D-1
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Furthermore, even at the $10,000/ton cost threshold, AQAT still 

projects Liberty-Clairton to face maintenance concerns with the 

annual PM2.5 standard and is projected to remain in nonattainment of 

the 24-hour PM2.5 standard, while the Chicago49 and Lancaster areas are 

still projected to have residual maintenance problems with the 24-

hour PM2.5 standard. EPA projected that even total elimination of EGU 

SO2 emissions (no matter the cost) would not be able to resolve either 

nonattainment of the 24-hour PM2.5 standard in the Liberty-Clairton 

area or the residual maintenance concerns with that standard in 

 

49 This area is not currently designated as nonattainment for the 24-

hour PM2.5 standard. EPA is portraying the receptors and counties in 

this area as a single 24-hour maintenance area based on the annual 

PM2.5 nonattainment designation of Chicago-Gary-Lake County, IL-IN.
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Lancaster County. EPA thus finds that other PM2.5 strategies, 

including local reductions of other PM2.5 precursors, are important to 

consider for remaining nonattainment and maintenance areas to seek 

further improvements in PM2.5 concentrations.

Considering both air quality and cost, EPA’s multi-factor 

analysis indicated $2,300 per ton as an appropriate cost threshold

for SO2 in the Group 1 states. EPA believes the analyzed cost 

thresholds lower than $2,300/ton were not appropriate for SO2 control 

in the Group 1 states under the Transport Rule for the following 

reasons:

 Downwind air quality impacts up to the $2,300 threshold are 

significant. Moving up to $2,300/ton successfully resolves all 

downwind nonattainment of the annual and 24-hour PM2.5 standards 

except for the Liberty-Clairton receptor in Allegheny county

with respect to 24-hour PM2.5, which EPA has noted is heavily 

influenced by a local source of organic carbon (75 FR 45281).

 Upwind emission reductions available up to $2,300/ton are highly 

cost-effective compared with similar regulations.

 The emission reductions up to this threshold are achievable with 

widespread deployment of controls that can be installed at power 

plants by 2014.

 As stated at proposal, EPA finds it reasonable to require a 

substantial level of control of upwind state emissions that 

significantly contribute to nonattainment or maintenance 
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problems in another state. The $2,300/ton cost threshold is 

comparable to EPA’s survey of local non-EGU SO2 reduction 

opportunities in the PM2.5 NAAQS RIA, which range in cost from 

just above $2,300/ton to over $16,000/ton (2007 $). EPA thus 

finds it reasonable to seek EGU SO2 reductions up to $2,300/ton 

(rather than at a lower cost threshold) in the states linked to 

receptors with ongoing attainment and maintenance concerns with 

the PM2.5 NAAQS.

EPA believes the analyzed cost thresholds above $2,300/ton were 

not appropriate for SO2 control in the Group 1 states under the 

Transport Rule for the following reasons:

 As noted above, AQAT suggests reductions up to $2,300/ton were 

able to resolve all projected downwind nonattainment of the 

annual and 24-hour PM2.5 NAAQS, with the sole exception of 

projected nonattainment of the 24-hour PM2.5 standard at a 

receptor in Liberty-Clairton. It is well-established that, in 

addition to being impacted by regional sources, the LibertyClairton area is significantly affected by local emissions from 

a sizable coke production facility and other nearby sources, 

leading to high concentrations of organic carbon in this area.50 

EPA finds that the remaining PM2.5 nonattainment problem is 

predominantly local and therefore does not believe that it would 

be appropriate to establish a higher cost threshold solely on 

 

50http://www.epa.gov/pmdesignations/2006standards/final/TSD/

tsd_4.0_4.3_4.3.3_r03_PA_2.pdf
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the basis of this projected ongoing nonattainment of the 24-hour 

PM2.5 standard at the Liberty-Clairton receptor.

 Approximately 70 percent of base case SO2 emissions from Group 1 

states were eliminated at the $2,300/ton cost threshold, leaving 

a decreasing amount of emission reductions available at each 

increased cost threshold beyond $2,300/ton. 

 Additional EGU SO2 reductions available from EGUs beyond the 

$2,300/ton threshold level realize significantly less 

improvement in downwind PM2.5 concentrations per dollar spent to 

impact receptors linked to Group 1 states. In other words, the 

cost-effectiveness of controlling EGU emissions in Group 1 

states to improve downwind PM2.5 concentrations at the linked 

receptors is notably diminished beyond the $2,300/ton threshold 

in this analysis. See Figure VI.D-1.

 EGUs are by far the largest source category for SO2 emissions. 

This analysis shows that reductions of EGU SO2 emissions up to 

the $2,300/ton cost threshold were significantly more costeffective for improving downwind PM2.5 concentrations than 

further such reductions (beyond the $2,300/ton cost threshold)

would be to address the remaining PM2.5 maintenance concerns. 

EPA’s analysis also shows that these maintenance concerns cannot 

be fully resolved even with complete elimination of all 

remaining EGU SO2 emissions, no matter the cost. EPA finds that 

other PM2.5 precursor emission reductions, particularly those 
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from local sources will be critical for states in these 

remaining areas to consider for controlling PM2.5 concentrations 

with respect to maintenance of the 2006 24-hour PM2.5 NAAQS. 

In summary, the appropriate cost thresholds for each state were 

identified through the multi-factor assessment. This assessment 

included both cost and air quality considerations. As explained 

above, the ozone-season NOX threshold was determined to be $500/ton 

for all states required to reduce ozone-season NOX, with residual 

nonattainment and maintenance concerns to be addressed in a future 

rulemaking addressing a broader set of source categories for 

additional cost-effective reductions. For PM2.5, the appropriate cost 

threshold for each state was determined to be either the level at 

which nonattainment and maintenance issues were completely resolved 

in downwind states to which the state is linked, the level where 

remaining nonattainment and maintenance issues are primarily local, 

or where we found greatly diminished improvements in air quality 

occurring if EPA moved further up the cost curve. This assessment 

yielded a cost threshold of $2,300/ton on SO2 for Group 1 states 

starting in 2014 ($500/ton in 2012), a cost threshold of $500/ton on 

SO2 for Group 2 states, and a cost threshold of $500/ton on annual NOX

for all states required to reduce emissions for purposes of the 

annual or 24-hour PM2.5 NAAQS in this rule.

As explained above, none of these specific cost thresholds

establish any precedent for the cost per ton stringency of reductions 

EPA may require in future transport-related rulemakings; these 
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specific cost thresholds are based on current analyses of air quality 

and cost of emission reductions with respect to the NAAQS considered 

in this rulemaking and thus would not be relevant to future 

rulemakings (which would consider updated information) or rulemakings 

with respect to different NAAQS. In particular, EPA acknowledges 

that additional action EPA will require in a subsequent rulemaking to 

address significant contribution to nonattainment and interference 

with maintenance of the 2008 ozone NAAQS (once reconsideration is 

finalized) is very likely to require a higher cost per ton stringency 

of ozone-season NOX control applied to a broader set of source 

categories from upwind states than found to be appropriate for this 

rulemaking.

2. State Emission Budgets (Step 4) 

a. Budget Methodology

EPA used the multi-factor assessment to identify, for each 

state, the cost threshold that should be used to quantify that 

state’s significant contribution. As described above, in the context 

of this rulemaking EPA identified a cost threshold of $500/ton for 

ozone-season NOX control for all states required to reduce ozoneseason NOX emissions for purposes of the 1997 ozone NAAQS in this 

rule. EPA also identified a cost threshold of $500/ton for annual NOX

control for all states required to reduce annual NOX emissions for 

purposes of the annual or 24-hour PM2.5 NAAQS in this rule. Finally, 

EPA identified a cost threshold of $500/ton of SO2 starting in 2012

for all states required to reduce SO2 emissions for purposes of the 
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annual or 24-hour PM2.5 NAAQS in this rule, and $2,300/ton for the 

Group 1 states starting in 2014. 

EPA used these cost thresholds from the multi-factor analysis to 

quantify each state’s emissions that significantly contribute to or 

interfere with maintenance downwind. For example, for a Group 1 

state, EPA modeling of the cost threshold conveys emission reductions 

available in each covered state from operation of existing pollution 

controls as well as all emission reductions available at cost 

thresholds of $500/ton for annual NOX in 2012 and 2014, $500/ton for 

SO2 in 2012, and $2,300/ton for SO2 in 2014. The total SO2 and NOX

projected at these cost levels in that state in those years 

represents that state’s emissions once significant contribution to 

nonattainment or interference with maintenance downwind for the 

relevant PM2.5 NAAQS has been eliminated.

Table VI.D-2 Example of Emission Reductions and Budget 

Formation in Pennsylvania for Annual SO2 and NOX

a

Final 

Cost 

Threshold

Base Case 

Emissions 

(1000 

tons)

Remaining 

Emissions 

at Cost 

Thresholds 

(1000 tons)

Emissions 

Eliminated 

(1000 

tons)

A B C D E F

2012

SO2 $500 493 279 215

NOX $500 129 120 9

2014

SO2 $2,300 507 112 395

NOX $500 132 119 13

a Note: In this table, emissions are shown for fossilfuel-fired EGUs > 25 MW (i.e., those units likely covered 

by the Transport Rule). Table VI.D.2 illustrates how 

budgets are derived from the elimination of significant 

contribution for the state of Pennsylvania. Column C 
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illustrates the cost thresholds applied in the costing run 

that was ultimately identified as the final cost threshold 

in the multi-factor analysis. Column D shows the base 

case emissions for the identified pollutant in the 

identified time period. Column E shows the emission 

levels that result when the cost thresholds identified in 

column C are applied. Because this is the cost threshold 

identified through the multi-factor analysis and the point 

where all significant contribution to nonattainment and 

interference with maintenance has been addressed for the 

PM2.5 NAAQS -- state budgets are based on these emission 

levels. The final column illustrates the emission 

reductions for the state in an average year (before 

accounting for variability).

EPA’s modeling of a state’s SO2 and annual NOX emission levels 

(from fossil-fired EGUs >25 MW) at the relevant cost thresholds in 

each state reflect that state’s emissions from covered sources after 

the removal of significant contribution to nonattainment and 

interference with maintenance of the PM2.5 NAAQS considered in this 

rulemaking. As these state emission levels reflect the removal of 

significant contribution and interference with maintenance, they are 

reasonable levels on which to determine state budgets. Consequently, 

EPA based state budget levels on the state level emissions that 

remained at the cost threshold. Each state’s budget corresponds to 

its emission level following the elimination of significant 

contribution to nonattainment and interference with maintenance in an 

average year (before taking year-to-year variability into account, as 

discussed in section VI.E below). Therefore, the implementation and 

realization of these budgeted emission levels leads to the 

elimination of significant contribution to nonattainment and 

interference with maintenance and EPA meets the statutory mandate of 
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section 110(a)(2)(D)(i)(I) with respect to the 1997 annual PM2.5 NAAQS 

and the 2006 24-hour PM2.5 NAAQS.

EPA’s establishment of state budgets for ozone-season NOX control 

follow the same methodology as described above for SO2 and annual NOX. 

Implementation of these ozone-season NOX budgets reflects the 

elimination of significant contribution to nonattainment and 

interference with maintenance of the 1997 ozone NAAQS for 15 states, 

whereas 11 other states’ ozone-season NOX budgets reflect meaningful 

progress toward (but may not reflect full completion of) this 

elimination under the mandate of section 110(a)(2)(D)(i)(I). See

section III for lists of states.

This approach to basing budgets on projected state level 

emissions used in the multi-factor analysis is identical to the 

approach used in the proposal for determining 2014 SO2 budgets for 

Group 1 states. EPA is extending this approach more broadly in the 

final Transport Rule to create state budgets for ozone-season NOX, 

annual NOX, and SO2 in all relevant states in both 2012 and 2014. In 

the proposal EPA used a more complex approach based on a comparison 

of historic and projected unit-level emissions (further adjusted for 

operation of existing controls) in each state to create 2012 state 

budgets for ozone-season NOX, annual NOX, and Group 2 SO2. At the 

time of proposal, EPA believed that historic 2009 emissions data were 

in some cases more representative of expected emissions in 2012 than 

pure modeling projections made at the time (75 FR 45290).
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However, following the proposal EPA has made significant updates 

to the IPM model for projecting EGU emissions, including specifically 

the adoption of 2009 historic data into its modeling parameters 

directly. EPA also received substantial public input following the 

proposal on the model’s assumptions and representation of individual 

units, which allowed EPA to improve its 2012 and 2014 emission 

projections for states under the cost thresholds considered. These 

modeling updates diminish the concerns EPA expressed at proposal that 

2009 historic data may have offered for some states a better proxy 

for 2012 emissions than model projections, particularly now that EPA 

is incorporating 2009 data directly in its updated modeling 

projections. Given these updates to the model in response to public 

comment, EPA believes it is more appropriate for the final rule to 

use a consistent approach based on projected state level emissions 

for all state budgets, as was done for Group 1 SO2 budgets in 2014 at 

proposal. EPA received significant comment supporting the use of the 

model to project state-level emissions for creating budgets in this 

manner. EPA also received comments that criticized the proposal’s 

methodology for 2012 budgets for lack of transparency, unnecessary 

complexity, and inconsistency with the state-level emission 

projections used in the air quality modeling. EPA’s decision for the 

final Transport Rule to consistently apply across all pollutants the 

budget methodology originally used for Group 1 SO2 budgets in 2014 

addresses those concerns.
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This budget methodology for the final rule uses projected statelevel emissions in 2012 and 2014 to set emission budgets for those 

years on relevant pollutants for that state to control under the 

Transport Rule. EPA’s modeling projects that some states have 2014 

emissions that are lower than their 2012 projected emissions even as 

the same cost threshold (e.g., $500/ton) is applied in both years. 

This occurs in the annual NOX, ozone-season NOX, and Group 2 SO2

program. As such, EPA’s application of this budgeting methodology 

results in a tightening of budgets in states whose projected 

emissions of that budgeted pollutant decline from 2012 to 2014 as the 

cost threshold is held constant. 

There are two primary variables that explain the decrease in 

emissions for some states between 2012 and 2014 as the cost threshold 

remains constant over both time periods. First, even though the cost 

threshold is constant between 2012 and 2014 for the programs noted 

above, the cost threshold for SO2 Group 1 increases in 2014. This 

higher cost threshold for Group 1 SO2 results in obvious reductions in 

SO2 emissions in the Group 1 states, but also may lower the cost of 

certain related NOX reductions in those states as well such that they 

become newly available within the $500/ton threshold. For example, 

if a state increases natural gas generation in response to the higher 

SO2 cost threshold, such action also yields additional annual and 

ozone-season NOX emission reductions that are cost-effective at the 

$500/ton NOX threshold. Where the cost curve modeling shows such 

additional cost-effective NOX reductions in tandem with SO2 control, 
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EPA is therefore reducing those states’ 2014 annual NOX and ozoneseason NOX budgets accordingly, so that those budgets accurately 

reflect remaining emissions from covered sources in those states 

after the elimination of all emissions that can be reduced up to the 

relevant cost thresholds (e.g., $500/ton).

Second, some of these additional reductions are driven by nonTransport Rule variables. These are reductions that occur due to 

state rules, consent decrees, and other planned changes in generation 

patterns that occur after 2012, but during or prior to 2014. For 

example, EPA modeling reflects emission reduction requirements under 

provisions of a Georgia state rule that go into effect after 2012 but 

before 2014. These requirements involve the installation and 

operation of specific advanced pollution controls. These sourcespecific requirements under a legal authority unrelated to the 

Transport Rule result in sharp reductions in Georgia’s baseline 

emission projections between 2012 and 2014. Even though the cost 

threshold for NOX and for SO2 in Georgia is $500/ton in both 2012 and 

2014, EPA believes it is important to establish separate NOX and SO2

budgets that accurately reflect the emissions remaining in Georgia 

(and other states experiencing similar reductions) after the 

elimination of emissions that can be reduced up to the Transport Rule 

remedy’s cost thresholds (e.g., $500/ton) (see Table VI.D.3). It 

illustrates a notable decrease between the 2012 and 2014 state 

budgets for NOX and SO2 in Georgia that is largely driven by state 

rule requirements. If EPA did not adjust 2014 budgets to account for 
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other emission reductions that would occur even in the baseline, 

other sources within the state would be allowed to increase their 

emissions under the unadjusted Transport Rule budgets to offset the 

emission reductions planned under other requirements such as state 

rules. Therefore, to prevent the Transport Rule from allowing such 

offsetting of emission reductions already expected to occur between 

2012 and 2014, EPA is establishing separate budgets for 2012 and 2014 

in the final Transport Rule to capture emission reductions in each 

state that would occur for non-Transport Rule-related reasons (i.e., 

in the base case) during that time.

EPA’s modeling also projects that other states would slightly 

increase emissions from 2012 to 2014 even at the same cost threshold, 

such as $500/ton. There are two primary variables that explain the 

increase in emissions for these states between 2012 and 2014. These 

increases are generally small in magnitude. For annual and ozone 

season NOX, they occur as a byproduct of small changes in dispatch 

related to changes in non-Transport Rule factors (e.g., higher demand 

in 2014). For SO2, they primarily occur in Group 2 states and, in 

addition to the reasons given above, are influenced by some 

generation shifting from Group 1 to Group 2 states as the Group 1 

states begin to face a higher cost threshold in 2014. EPA believes 

that allowing for such emission growth in covered states beyond 2012 

would be inconsistent with the Transport Rule’s identification and 

elimination of significant contribution to nonattainment and 

interference with maintenance beginning in 2012. Therefore, for any 
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covered state whose emissions of a relevant pollutant are projected 

to increase from 2012 to 2014 under the relevant cost thresholds 

selected in the multi-factor analysis described above, EPA is 

finalizing that state’s 2014 emission budget to maintain the same 

level of the 2012 emission budget, thereby disallowing such an 

emission increase that is inconsistent with the 110(a)(2)(D)(i)(I) 

mandate. Tables VI.D-3 and VI.D-4 below list state emission 

budgets.51 

Table VI.D-3 - SO2 and Annual NOX State Emission Budgets for Electric 

Generating Units before Accounting for Variability* (tons)

SO2 NOX

Group 2012-2013

2014 and 

beyond 2012-2013

2014 and 

beyond

Alabama 2 216,033 213,258

 

72,691 

 

71,962 

Georgia 2 158,527 95,231

 

62,010 

 

40,540 

Illinois 1 234,889 124,123

 

47,872 

 

47,872 

Indiana 1 285,424 161,111

 

109,726 

 

108,424 

Iowa 1 107,085 75,184

 

38,335 

 

37,498 

Kansas 2 41,528 41,528

 

30,714 

 

25,560 

Kentucky 1 232,662 106,284

 

85,086 

 

77,238 

Maryland 1 30,120 28,203 

 

51 These budgets include minor technical corrections to SO2 budgets in 

three states (KY, MI, and NY) that were made after the impact 

analyses for the final rule were conducted. EPA conducted 

sensitivity analysis confirming that these differences do not 

meaningfully alter any of the Agency’s findings or conclusions based 

on the projected cost, benefit, and air quality impacts presented for 

the final Transport Rule. The results of this sensitivity analysis 

are presented in Appendix F in the final Transport Rule RIA.
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16,633 16,574 

Michigan 1 229,303 143,995

 

60,193 

 

57,812 

Minnesota 2 41,981 41,981

 

29,572 

 

29,572 

Missouri 1 207,466 165,941

 

52,374 

 

48,717 

Nebraska 2 65,052 65,052

 

26,440 

 

26,440 

New Jersey 1 5,574 5,574

 

7,266 

 

7,266 

New York 1 27,325 18,585

 

17,543 

 

17,543 

North 

Carolina 1 136,881 57,620

 

50,587 

 

41,553 

Ohio 1 310,230 137,077

 

92,703 

 

87,493 

Pennsylvania 1 278,651 112,021

 

119,986 

 

119,194 

South 

Carolina 2 88,620 88,620

 

32,498 

 

32,498 

Tennessee 1 148,150 58,833

 

35,703 

 

19,337 

Texas 2 243,954 243,954

 

133,595 

 

133,595 

Virginia 1 70,820 35,057

 

33,242 

 

33,242 

West 

Virginia 1 146,174 75,668

 

59,472 

 

54,582 

Wisconsin 1 79,480 40,126

 

31,628 

 

30,398 

Grand Total 3,385,929 2,135,026 1,245,869 1,164,910

Group 1 

Total 2,530,234 1,345,402 NA NA

Group 2 

Total 855,695 789,624 NA NA

Note - These state emission budgets apply to emissions from 

electric generating units covered by the Transport Rule 

Program. Group 1/Group 2 designations are only relevant 

for SO2 emissions budgets.

*The impact of variability on budgets is discussed in 

section VI.E

The District of Columbia is not covered by the final Transport 

Rule. As discussed in section V.D of this preamble and as done for 
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the Transport Rule proposal, EPA combined contributions projected in 

the air quality modeling from Maryland and the District of Columbia 

to determine whether those jurisdictions collectively contribute to 

any downwind nonattainment or maintenance receptor in amounts equal 

to or greater than the 1 percent thresholds. This modeling confirmed 

that the combined contributions exceed the air quality threshold at 

downwind receptors for the ozone, annual PM2.5, and 24-hour PM2.5 NAAQS 

considered. Both Maryland and the District of Columbia are therefore 

linked to these receptors.52 However, the District of Columbia is not 

included in the Transport Rule because, in the second step of EPA’s 

significant contribution analysis, we concluded that there are no 

emission reductions available from EGUs in the District of Columbia 

at the cost thresholds deemed sufficient to eliminate significant 

contribution to nonattainment and interference with maintenance of 

the NAAQS considered at the linked receptors. At the time of this 

rulemaking, EPA finds only one facility with units meeting the 

Transport Rule applicability requirements in the District of 

Columbia. EPA’s projections do not show any generation from this 

facility to be economic under any scenario analyzed (including the 

base case), and the facility’s owners have also announced plans to 

 

52 It is important to note that Maryland’s modeled contributions in 

isolation were greater than the 1 percent threshold for all three of 

the NAAQS considered at all of the same receptors for which Maryland 

and DC were “linked,” and therefore EPA would have considered 

Maryland “linked” to the same set of downwind receptors even if the 

Agency had treated Maryland’s contributions and the District of 

Columbia’s contributions separately.
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retire its units in early 2012.53 Therefore, this unit is projected 

to have zero emissions in 2012. As such, the total SO2 and NOX

emissions in the District of Columbia for EGUs that meet the 

Transport Rule applicability requirements is also projected to be 

zero. It follows therefore, that EPA did not identify any emission 

reductions available at any of the cost thresholds considered in the 

final rule’s multi-factor analysis to identify significant 

contribution to nonattainment and interference with maintenance. For 

this reason, EPA concludes that no additional limits or reductions 

are necessary, at this time, in the District of Columbia to satisfy 

the requirements of section 110(a)(2)(D)(i)(I) with respect to the 

1997 ozone, the 1997 PM2.5 and the 2006 PM2.5 NAAQS. EPA is therefore 

neither establishing budgets nor finalizing any FIPs for the District 

of Columbia in this rule.

Table VI.D-4 - Ozone Season NOX State Emission Budgets for Electric 

Generating Units before Accounting for Variability* (tons)

2012-

2013

2014 and 

Beyond

Alabama 31,746 31,499 

Arkansas 15,037 15,037 

Florida 27,825 27,825 

Georgia 27,944 18,279 

Illinois 21,208 21,208 

Indiana 46,876 46,175 

Kentucky 36,167 32,674 

 

53 The future retirement status of this D.C. facility was also 

supported by its inclusion on PJM's future deactivation list. PJM 

further suggested that reliability issues related to their retirement 

are expected to be resolved by next year in time for its planned 

retirement date. (See PJM pending deactivation request in TR 

Docket.)
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Louisiana 13,432 13,432 

Maryland 7,179 7,179 

Mississippi 10,160 10,160 

New Jersey 3,382 3,382 

New York 8,331 8,331 

North Carolina 22,168 18,455 

Ohio 40,063 37,792 

Pennsylvania 52,201 51,912 

South Carolina 13,909 13,909 

Tennessee 14,908 8,016 

Texas 63,043 63,043 

Virginia 14,452 14,452 

West Virginia 25,283 23,291 

Total 495,314 466,051 

Note - These state emission 

budgets apply to emissions from 

electric generating units covered 

by the Transport Rule Program. 

Group 1/Group 2 designations are 

only relevant for SO2 emissions 

budgets.

*The impact of variability on 

budgets in discussed is section 

VI.E

EPA notes that the NOX budgets for five states linked to downwind 

ozone receptors in the final Transport Rule are equal to their 

projected 2012 base case emissions. The five states are Arkansas, 

Indiana, Louisiana, Maryland, and Mississippi. These states are 

among those found to meet or exceed the 1 percent contribution 

threshold for the 1997 ozone NAAQS at downwind receptors and are thus 

“linked” to downwind receptors. EPA therefore evaluates, in the 

second step of its significant contribution analysis, what emission 

limits are necessary to ensure that all emissions that constitute the 

state’s significant contribution to nonattainment and interference 
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with maintenance are prohibited. As explained above, EPA decided to 

require from all such states all reductions available at the $500/ton 

cost threshold. The five states identified above do not appear to 

show EGU ozone-season NOX reductions at the $500/ton cost threshold 

relative to the 2012 base case projections (which do not take into 

account reductions to be made in other states as a result of this 

rule). Therefore, EPA conducted further analysis to evaluate whether 

such reductions were available in these states and whether emission 

limits are necessary to prohibit these states from significantly 

contributing to downwind nonattainment or interfering with 

maintenance of the 1997 ozone NAAQS in other states. (See the docket 

to this rulemaking for the IPM run titled 

TR_uncontrolled_ozone_states_Final.")

Specifically, EPA projected those states’ ozone-season NOX

emissions if all other linked states (but not these five states) were 

to make all available reductions at the $500/ton threshold. That 

analysis revealed that if emission limits were not established for 

these five states, ozone-season NOX emissions in each of the states 

would increase (beyond the 2012 base case emission projections), due 

to interstate shifts in electricity generation that cause “emissions 

leakage” in uncovered states. These increases would result in each 

state’s emissions being above the level associated with the 

prohibition of all emissions that can be eliminated at the $500/ton 

threshold. EPA thus determined that it is necessary to establish 

emission limits for these states at the $500/ton level. These 
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limits, although equal to the state’s 2012 projected base case

emissions, are necessary to prohibit all emissions that can be 

controlled at the $500/ton cost threshold. In other words, the 

significant contribution to nonattainment and interference with 

maintenance addressed by the ozone FIPs for these states is the 

difference between these states’ projected emissions if they were not 

covered under the Transport Rule (but other states were), and their 

emissions after all emissions that can be eliminated at $500/ton are 

prohibited. 

In addition, EPA notes that four of these five states (Arkansas, 

Indiana, Louisiana, and Mississippi) are linked to receptors in 

either the Houston or Baton Rouge areas, which are projected to 

continue facing nonattainment or maintenance concerns with the 1997 

ozone NAAQS, respectively. To allow these states to increase 

emissions above base case projections would erode the measurable 

progress toward eliminating significant contribution to nonattainment

and interference with maintenance secured by achieving ozone-season 

NOX reductions in the other states linked to these receptors. 

Furthermore, as discussed in section III, EPA may require additional 

reductions in these states to fully address significant contribution 

to nonattainment and interference with maintenance with respect to 

the 1997 ozone NAAQS in a future rulemaking to be proposed after 

finalizing reconsideration of the 2008 ozone NAAQS.

b. Relationship of Group 1 and Group 2 States for SO2 Control
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In the Proposal, EPA chose not to allow sources in Group 1 

states to use Group 2 SO2 allowances for compliance, and likewise not 

to allow sources in Group 2 states to use Group 1 SO2 allowances for 

compliance at any time. The preamble clearly states, “With regard to 

interstate trading, the two SO2 stringency tiers would lead to two 

exclusive SO2 trading groups. That is, states in SO2 Group 1 could not 

trade with states in SO2 Group 2” (75 FR 45216). No such distinction 

or limitation exists for NOX allowance trading.

EPA received significant public comment both in support and 

opposition to the two distinct SO2 trading programs. Those in 

opposition noted that the variability limits imposed at the state 

level made the compliance restrictions between the two groups 

unnecessary. Commenters also noted that it may unfairly penalize 

sources that are part of the same airshed, but are on opposite sides 

of a state boundary. Those in favor of the separate SO2 compliance 

programs noted that it would reduce the probability of a state 

exceeding its variability limit. Allowing the use of Group 1 or 

Group 2 allowances for compliance between the two SO2 programs would 

potentially encourage Group 1 states to purchase allowances instead 

of making reductions necessary to eliminate significant contribution. 

Group 1 states are states that need continued reductions (beyond the 

$500/ton threshold) to eliminate their significant contribution to 

nonattainment and interference with maintenance. Group 2 states have 

already eliminated their significant contribution to nonattainment 

and interference with maintenance at the $500/threshold. So to allow 
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Group 1 or Group 2 allowances to be used interchangeably for 

compliance between the two SO2 groups would be to allow the shifting 

of reductions from areas where they are needed to eliminate 

significant contribution to nonattainment and interference with 

maintenance to areas where they are not needed to eliminate the 

prohibited emissions. EPA also agrees that allowing for trading 

between the two groups in the remedy finalized in this action would 

increase risk of a state exceeding its variability limit. For these 

reasons, EPA is finalizing this rulemaking with the same prohibition 

on SO2 trading between Group 1 and Group 2 states that was defined in 

the proposal. Further, EPA clarifies that while trading of 

allowances (i.e., buying, selling, and banking) is allowed without 

restriction, it is specifically the surrender of SO2 allowances for 

compliance that is limited. As mentioned earlier, a source in a 

Group 1 state can only use SO2 allowances allocated to Group 1 states 

for compliance with the SO2 trading program. Likewise, a source in a 

Group 2 state can only use SO2 allowances allocated to Group 2 states 

for compliance with the SO2 trading program.

c. Ozone-Season Budgets

EPA established the ozone-season NOX budgets in a similar manner 

to the annual NOX and SO2 budgets by using the state level emissions 

from the cost threshold that reflected the removal of significant 

contribution to nonattainment and interference with maintenance. 

Ozone-season budgets were based on the state level emissions from 

fossil-fuel-fired units greater than 25 MW observed at this cost 
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threshold. As described in section VI.B, all cost thresholds

examined reflected the final Transport Rule geography and the 

marginal costs were applied accordingly. Therefore, for an ozoneonly state like Florida, the state level emissions would only reflect 

an ozone-season cost threshold of $500/ton in the final cost curves 

for 2012 and 2014. For a state subject to both annual and ozoneseason programs, the marginal cost curves would reflect a $500/ton NOX

cost year round, a $500/ton SO2 cost in 2012 and the $2,300/ton SO2

cost starting in 2014 if a Group 1 state. 

(1) Length of ozone season

(a) Proposed Rule. For purposes of determining ozone-season 

budgets in the proposed rule, EPA defined the ozone season based on a 

5 month period (May 1 through September 30). This 5 month ozone 

season was consistent with the approach taken by the OTAG, the NOX SIP 

Call, and CAIR. EPA requested comment on whether EPA should base 

final rule budgets on a longer season, such as March through October. 

(b) Public Comments. Several commenters supported continuing 

with the May through September time period. One commenter supported 

continuing with this time period, but argued that EPA should consider 

lengthening the ozone season for future efforts. One commenter 

questioned the concept of ozone season budgets and recommended EPA 

focus on sources with greater emissions on high ozone days. 

(c) Final rule. For the final rule, EPA has retained the 

approach in the proposed rule, as commenters broadly supported the 

proposal’s ozone-season duration and ozone-season NOX limitations. 
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Notably, many Transport Rule states covered for PM2.5 reductions will 

have sources with annual NOX controls that are likely to keep 

operating year round to address PM2.5 and ozone. EPA believes that 

experience from ozone-season NOX trading has consistently shown that 

the emission measures taken to comply with ozone-season budgets 

provide emission reductions throughout the ozone-season, including 

the highest ozone days. (See NOX Budget Trading Program and CAIR 

Program progress reports in the docket to this rulemaking or at 

http://www.epa.gov/airmarkets/progress/nbp08.html and 

http://www.epa.gov/airmarkets/progress/CAIR_09/CAIR09.html.) 

However, EPA believes that there is merit in future Agency actions 

addressing ozone transport in considering strategies to target high 

ozone days more specifically.

d. Summary of Cost Thresholds and Final Budgets for PM2.5 and 

Ozone

Summary of methodology. In summary, EPA determined that SO2

emissions that could be reduced for $2,300/ton in 2014 should be 

considered a state’s significant contribution to nonattainment and 

interference with maintenance, unless EPA determined that a lesser 

reduction would fully resolve the nonattainment and/or maintenance 

problem for all the downwind receptors 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. This level is 

defined by the reductions observed in the $500/ton cost threshold. 
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EPA also determined that all states linked to downwind PM2.5

nonattainment and maintenance problems should be required to achieve 

those emission reductions that can be reasonably achieved by 2012. 

Finally, EPA determined that all states linked to downwind PM2.5

nonattainment and maintenance problems should, by 2012, remove all NOX

emissions that can be reduced for $500/ton and run all existing 

controls in 2012. 

For ozone-season NOX, EPA determined that all states linked to 

downwind ozone and nonattainment and maintenance problems should be 

required to achieve those ozone-season emission reductions associated 

with a cost threshold of $500 per ton. Additionally, EPA examined 

final 2012 and 2014 budgets based on state level emissions at $500 

cost threshold.

The budget formation methodology finalized in this action 

responds to concerns about state budgets expressed by commenters on 

the Transport Rule proposal. EPA requested comment on the four step 

approach used to determine significant contribution and determine 

budgets in the proposal. Some commenters noted that the state level 

emissions from the cost thresholds used to determine significant 

contribution to nonattainment and interference with maintenance did 

not match the state level emissions allowed by the final budgets. 

The concern was that the state level emissions that reflected the 

elimination of significant contribution in the AQAT analysis, in 

particular for NOX, were less than the emissions allowed by the final 

budgets. The result would be an implementation that did not quite 
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fully eliminate the significant contribution to nonattainment and 

interference with maintenance defined in the rule. The proposed 

budgets not matching the levels reflected in the proposed costing 

runs were an artifact of the budget formation process that relied on 

a combination of historic and projected data. While EPA noted this 

process resulted in state budgets that “reflected” EGU emissions at 

$500/ton, it was not always consistent with the EGU emissions at 

$500/ton in the costing runs as the commenters noted. By using the 

cost curves to determine both significant contribution to 

nonattainment and interference with maintenance -- and state budgets

-- in the final rule, EPA addresses the commenter’s concerns about 

any inconsistency between the two in the proposal.

Some commenters expressed concern that the Transport Rule would 

result in state budgets that were in some cases higher than those 

established in CAIR. Commenters suggested that this would be 

inconsistent with requirements or the spirit of certain CAA 

provisions aimed at preventing backsliding, i.e., sections 110(l), 

172(e), and 193. However, the D.C. Court of Appeals rejected the 

state budgets in CAIR as arbitrary and capricious and not consistent 

with CAA section 110(a)(2)D)(i)(I) (North Carolina, 531 F.3d 918 and 

921) and remanded CAIR to EPA to promulgate a new rule replacing CAIR 

and consistent with the Court's decision (North Carolina, 550 F.3d 

1178). As discussed elsewhere in this section, on remand EPA 

developed new, final state budgets that address the Court's concerns 

and meet section 110(a)(2)(D)(i)(I) requirements. 
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Although some state budgets under the final rule are higher than 

those under CAIR, this does not violate either the letter or the 

spirit of CAA provisions aimed at backsliding. In particular, CAA 

section 110(l) provides that the Administrator may not approve a plan 

revision that would "interfere with any...applicable requirement" of 

the CAA. 42 U.S.C. 7410(l). Because the Court reversed and remanded 

CAIR with instructions to "remedy" the rule's "fundamental flaws" 

(including specifically the state budgets found to be unlawful (North 

Carolina, 550 F.3d 1178), it is difficult to see how new state 

budgets replacing unlawful budgets and meeting section 

110(a)(2)(D)(i)(I) requirements could be viewed as interfering with 

requirements of the CAA. Indeed, the commenters' approach would 

severely limit EPA's ability to meet the Court's mandate to develop a 

new rule consistent with section 110(a)(2)(D)(i)(I). See North 

Carolina, 531 F.3d 921 (explaining that EPA may not require "some 

states to exceed the mark" of eliminating their significant 

contribution). Further, the other CAA sections cited by the 

commenters (section 172(e), addressing circumstances where the 

Administrator relaxes a NAAQS, and section 193, addressing the 

treatment of requirements promulgated before the November 15, 1990, 

enactment date for the 1990 Amendments to the Clean Air Act) are not 

applicable here. 

Additionally, while the CAIR budgets may have been tighter than 

Transport Rule state budgets for a couple of states, the sum of state 

budgets that were subject to both CAIR and the Transport Rule is 
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lower under the Transport Rule for the annual programs. Moreover, 

the carryover of the large Title IV allowance bank in CAIR allowed 

for a great deal more emissions within any given state than is 

permitted under the Transport Rule.

E. Approach to Power Sector Emission Variability

1. Introduction to Power Sector Variability

Variability is an inherent aspect of the production and delivery 

of electricity. It follows that variations in state emissions are 

not only a result of variations in the level of emission control, but 

also are caused by the inherent variability in power generation. The 

state budgets do not account for this latter source of variability at 

the state level. Emission variability is built into the design of 

power systems, which use a wide mix of power generation sources with 

varying use and emission patterns to ensure reliability in electric 

power generation. Variations in weather, demand due to changes in 

the level of economic activity, the portion of electric generation 

that is fossil-fuel-fired, the length and number of outages at power 

generation units, and other factors, can lead to significant 

variations in the load levels of different power generation sources. 

Variations in the load levels of sources in any given state cause 

variations in the level of emissions in that state. Thus, EPA 

believes it is appropriate, in this rule, to take into account the 

variations that are caused by inherent variability in power 

generation. More specifically, variations in these external 
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variables can cause significant fluctuations in state emissions, even 

when action has been taken to prohibit all emissions within a state 

that significantly contribute to nonattainment or interfere with 

maintenance in another state. For this reason, EPA considers 

variability when determining the state specific requirements in this 

rule. EPA does so by developing variability limits and assurance 

levels for each state, as described in this section, that are 

consistent with the statutory mandate of CAA section 

110(a)(2)(D)(i)(I). 

Loads on a power system, and thus on power generation sources in 

a given state that are on the power system, vary over every time 

interval, changing not only in the short term and seasonally, but 

also annually. As noted above, load patterns and levels are 

determined by a multiplicity of factors, including weather, economic 

activity, the portion of electric generation that is fossil-fuelfired, and the length and number of outages at power generation 

units, which vary over time. In particular, weather obviously varies 

not just from season-to-season but also from year-to-year, and even 

small changes in annual weather patterns can affect how the power 

system and power generation sources on the power system operate

during a year. For example, load, and the resulting use of 

generation sources on an interconnected grid to meet load, depend not 

only on how hot a summer day is, but also on where a heat wave occurs 

and how long it lasts. Similarly, a relatively cold winter that 

drives up winter load may also change what generation sources are 
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used to address the increased demand for heat. Thus, the pattern of 

generation may shift geographically as a weather pattern moves across 

the country. Because weather and other factors affecting loads, and 

the patterns of generation used to meet loads, vary over time and 

from state to state, the resulting level of emissions also varies 

over time and from state to state. 

This variability in emissions is not a result of variation in 

emission rates, emission controls, or emission control strategies, 

but instead is a result of the inherent variability in power 

generation. Patterns of generation change to ensure demand for 

electricity is met and to ensure continued reliability of the power 

system. This results in temporal and geographic fluctuations in 

emissions. In the final Transport Rule, like the proposed rule, EPA 

explicitly takes account of these changing patterns of generation and 

the resultant variability in power sector emissions. 

As discussed previously, EPA identified a specific amount of 

emissions that must be prohibited by each state to meet the 

requirements of CAA section 110(a)(2)(D)(i)(I). EPA also developed 

state baseline emissions for power generation sources based on 

projections of state emissions in an average year before the 

elimination of prohibited emissions, and state budgets for power 

generation sources based on projections of state emissions in an 

average year after the elimination of such emissions. However, 

because of the inherent variability in state-level baseline emissions 

–- resulting from the inherent variability in loads and power system
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and power generation source operations -- state-level emissions will 

fluctuate from year-to-year even after all significant contribution 

to nonattainment and interference with maintenance that EPA 

identified in this final rule are eliminated. In an above average 

year, emissions may exceed the state budgets which are based on an 

analysis of projected emissions in an average year. EPA believes 

that, because baseline emissions are variable for reasons unrelated 

to the degree of emission control in a state and emissions after the 

elimination of all significant contribution to nonattainment and 

interference with maintenance are therefore also variable, it is 

appropriate to take this variability into account in developing the 

remedy for meeting the requirements of CAA section 

110(a)(2)(D)(i)(I). The variability limits and assurance levels in 

the final rule account for this inherent variability, while ensuring 

that emissions within each state that significantly contribute to 

nonattainment or interfere with maintenance in another state are 

prohibited. EPA believes this approach is both reasonable in that it 

reflects the operation of the power system generation in order to 

maintain electric reliability and consistent with the statutory 

mandate of CAA section 110(a)(2)(D)(i)(I). For these reasons, EPA is 

finalizing variability limits for each state budget to identify the 

range of emissions that EPA believes is likely to occur in each state 

following the elimination of all the state’s significant contribution 

to nonattainment and interference with maintenance. 
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As discussed above, the air quality-assured trading remedy’s 

state-specific budgets represent each state’s emissions in an average 

year after elimination of significant contribution to nonattainment 

and interference with maintenance. Because actual base case 

emissions are likely to vary from projected base case emissions, this 

remedy incorporates provisions that account for such variability. 

While the primary purpose of this remedy is to eliminate significant 

contribution and interference with maintenance, EPA believes 

variability limits also satisfy several other objectives. The remedy 

provides the flexibility to deal with real-world variability in the 

operation of the power system through air quality-assured trading and 

reduces costs of compliance with emission reduction requirements, 

while still providing assurance for downwind states that significant 

contribution to nonattainment and interference with maintenance by 

upwind states will be eliminated. EPA believes the limited 

fluctuation in state level emissions that this approach permits is 

consistent with the statutory mandate of section 110(a)(2)(D)(i)(I) 

because some geographic and temporal shifting of emissions 

necessarily results from the inherent variability in power generation 

and is caused by factors unrelated to the degree of emission control,

such as weather, economic activity, and unit availability. Far from 

excusing any state from addressing emissions within the state that 

significantly contribute to nonattainment or interfere with 

maintenance in other states, these variability limits ensure that the 

system can accommodate the inherent variability in the power sector 
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while ensuring that each state eliminates the amount of emissions 

within the state, in a given year, that must be eliminated to meet 

the statutory mandate of section 110(a)(2)(D)(i)(I). 

Moreover, the structure of the program, which achieves the 

required emission reductions through limits on the total number of 

allowances allocated, assurance provisions, and penalty mechanisms, 

ensures that the variability limits only allow the amount of temporal 

and geographic shifting of emissions that is likely to result from 

the inherent variability in power generation, and not from decisions 

to avoid or delay the installation of necessary controls. Under the 

remedy, an individual state can have emissions up to its budget plus 

the variability limit. However, the requirement that all sources 

hold allowances covering emissions, and the fact that those

allowances are allocated based on state-specific budgets without

variability, ensure that the total emissions from the states do not 

exceed the sum of the state budgets. The remedy, therefore, ensures 

both that total emissions do not exceed the total of the state 

budgets and that the required emission reductions occur in each 

state.

This section describes how EPA calculated variability limits for 

each state to achieve this goal.

2. Transport Rule Variability Limits

EPA performed analyses using historical data to demonstrate that 

there is year-to-year variability in base case emissions (even when 
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emission rates for all units are held constant) and to quantify the 

magnitude of this variability. 

The focus of the analysis is on quantifying the magnitude of the 

inherent year-to-year variability in state-level EGU emissions 

independent of measures taken to control those emissions (and thus 

due only to changes in electricity generation within each state). 

EPA used this analysis to set variability limits as part of the 

remedy to ensure that states are eliminating their significant 

contribution to nonattainment and interference with maintenance to 

protect air quality.

As discussed in detail below, EPA is finalizing the Transport 

Rule with 1-year variability limits calculated using a modified 

approach from the one described in the proposal. EPA is not 

including the proposal’s 3-year variability limits in the final 

Transport Rule. EPA received comments that the 3-year variability 

limits increased program costs and diminished compliance flexibility 

without delivering any additional air quality benefits. EGU owners 

and operators expressed concern that 3-year variability limits would 

be impracticable to implement and that the 1-year variability limits 

themselves would be adequately stringent to ensure elimination of 

significant contribution to nonattainment and interference with 

maintenance in each state.

After further consideration, EPA has concluded that 3-year 

variability limits would be unnecessary, would be difficult to 

anticipate, and would not have a measurable impact on air quality 
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benefits. EPA has determined that annual limits are sufficient to 

eliminate significant contribution to nonattainment and interference 

with maintenance in all upwind states while accommodating the 

historically observed year-to-year fluctuation in state-level EGU 

emissions even at the same rate of emissions control in a given 

state.

In the proposal, EPA used statistical methods to derive the 3-

year variability limit directly from the 1-year variability limit, 

meaning that the two are statistically equivalent in the long run 

under certain statistical assumptions. Primarily, these assumptions 

were that the variation in electric demand around the budget is 

random from year-to-year and that, when the annual emissions are 

averaged over a multi-year time period, the average emissions per 

year will equal the state’s budget. The first assumption was also 

made in the assessment of the historical year-to-year variation in 

heat input in developing the 1-year limit (see section 2 of the 

“Power Sector Variability Final Rule TSD” for more details). 

Regarding the second assumption, since the state-by-state emission 

budgets are based on the availability of emission reductions at an 

equal marginal cost level, EPA expects the sources in each of the 

upwind states to make these cost-effective reductions and to meet the 

emission budgets each year, on average. 

Since the 3-year variability limit was based on average year-toyear variability over a longer time horizon, EPA notes that a random 

ordering of those years could yield 2 above-average years in a row. 
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If, by chance, a third above-average year were to follow, the state 

could face violation of the 3-year limit, even if over a time period 

longer than 3 years, that state would never have exceeded the 

statistically-equivalent 1-year variability limit and its annual 

emissions would have averaged to the level of its budget. 

Effectively, this means that imposing a multi-year variability limit 

would erode the 1-year variability limit’s ability to accommodate 

historically observed year-to-year variability in state-level EGU 

emissions (due only to generation changes), and it would do so 

without providing any additional air quality benefits or protection 

for downwind areas (since the average emissions over the long time 

horizon equal the level of the budget).

For more details about the relationship between the 1- and 3-

year limits, see the discussions in section 3 of the “Power Sector 

Variability” TSD from the proposed Transport Rule, which describes 

the derivation of the 3-year limit from the 1-year variability and 

section 3 of the “Power Sector Variability Final Rule TSD”, which 

describes the results of a numerical simulation showing that the 1-

and 3-year limits are statistically indistinguishable and, thus, 

redundant over the course of the program to accommodate year-to-year 

variability. 

While EPA expects the yearly emissions in each state, on 

average, to equal the level of the budgets, EPA also estimated the 

air quality impacts of 5, 10, 15, and 20 percent emission variability 

using the air quality assessment tool, which is presented in section 
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4 of the “Power Sector Variability Final Rule TSD.” That analysis 

shows that year-to-year fluctuations of up to 20 percent in SO2

emissions from upwind states linked to a given downwind receptor do 

not undermine the ability of the Transport Rule programs to resolve 

nonattainment or maintenance concerns at that receptor. The analysis 

presented in the TSD focuses on SO2 emissions and was designed to 

examine the sensitivity of downwind air quality to upwind EGU 

emission levels. The share of total SO2 emitted by EGUs is 

significantly larger than the share of total NOX emitted by EGUs. For 

example, in the states for which EPA modeled base case contributions 

of these pollutants, EGUs accounted for 74 percent of total SO2, 14 

percent of total annual NOX, and 15 percent of total ozone-season NOX

emissions. Therefore, when varying EGU emissions only, downwind air 

quality would be most sensitive to upwind variations in SO2, because 

relative variations in EGU SO2 emissions have a greater impact on 

total SO2 emissions than the same relative variation in EGU NOX

emissions would have on total NOX emissions affecting downwind air 

quality. Because the Transport Rule only affects upwind emissions 

from EGU sources, downwind air quality would be more sensitive to 

variability in upwind state SO2 emissions under this rule than 

variability in upwind state NOX emissions under this rule (given that 

the rule affects a smaller scope of total NOX emissions compared to 

the scope affected of total SO2 emissions). Thus, EPA chose to 

analyze the “worst-case” potential downwind air quality impacts from 

year-to-year variability above upwind state SO2 budgets, and EPA 
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therefore believes that its findings from this analysis are valid for 

ascertaining the potential downwind air quality impacts from 

variation at those levels in both SO2 and NOX under the Transport Rule 

programs.

Furthermore, because the state budgets are based directly on IPM 

modeling of electric generation when cost-effective emission 

reductions have been achieved, sources within each state should have 

the same incentive to meet that budget, on average, in any given 

year. Additional EPA analysis supports the claim that states would 

be no more likely to exceed 1-year variability limits without the 3-

year limits than with the 3-year limits. See the “Power Sector 

Variability Final Rule TSD” for more details on this statistical 

analysis. Finally, because the state budgets (and thus the total 

amount of allowances available) are fixed and every covered source 

must hold allowances covering its emissions, it is not feasible for 

all, or even many, states to repeatedly exceed their budgets. 

The approach calculated the standard deviation in state-level 

heat input from units expected to be covered by the final Transport 

Rule over an 11-year time period (2000 through 2010), from which the 

95th percent confidence level was calculated. EPA divided this value 

by the mean to get the percentage variation in heat input. The twotailed 95th percent confidence level is the equivalent of the 97.5 

percent upper (single-tailed) confidence level. This approach 

yielded an average year-to-year heat input variability for each 

state, as a proxy for historic year-to-year variability in state-
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level EGU emissions while holding emission rates constant. The 

result, expressed as a percentage, conveys the maximum degree to 

which EGU emissions at the state level may be expected with 95th 

percent confidence to vary around a given target (i.e., budget) from 

year-to-year, on average, based on the statistical analysis of 

historic heat input over the 2000 through 2010 time period.

From the state-by-state variability calculations, EPA identified 

a single variability level (percentage) for each of the annual and 

ozone-season programs based on the historic variability measured at 

units in covered states on an annual basis and an ozone-season basis, 

respectively. In the proposal, EPA “identified a single set of 

variability levels . . . 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” (75 FR 

45293). In the final rule, EPA is taking the straightforward 

approach of identifying a single set of variability levels to apply 

to all states because EPA has determined that it is reasonable to 

afford all states under the Transport Rule programs the extent of 

measured historic variability experienced by any Transport Rule state

during 2000 through 2010. In the variability analysis for the final 

rule, EPA identified Tennessee as having the highest measured 

historic variability of annual heat input of 18 percent, and Virginia 

as having the highest measured historic variability of ozone-season 

heat input of 21 percent. Because the percentage of variability in 

Tennessee on an annual basis and in Virginia on an ozone-season basis 
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are reasonably likely to occur in each of the other states in the 

future, EPA believes it is appropriate to apply an 18 percent annual 

variability limit to all states covered by the annual SO2 and NOX

programs and a 21 percent ozone-season variability limit to all 

states covered by the ozone-season NOX program.

54

EPA’s analysis of historic heat input variability in multiple 

states over the 2000 to 2010 baseline yields a range of potential 

year-to-year variability values for state-level EGU emissions. As 

discussed above, any one state’s measured variability (in this case, 

from 2000 to 2010) is due to a multiplicity of factors. These 

factors include, but are not limited to, variation in weather, 

variation in demand due to increased or decreased level of economic 

activity, variation in the portion of electric generation that is 

fossil-fuel-fired, and variation in the length and number of outages 

at power generation units, and these individual factors may sometimes 

act in concert and may other times be offsetting. 

The mix and levels of factors present in a state from year-toyear can lead to variation of state-level emissions above and below 

the level for the state under average conditions. Because the levels 

of the various factors are difficult to predict on a year-to-year 

 

54 The six states in the supplemental proposal for inclusion in the 

Transport Rule’s ozone-season NOX program have measured historic 

ozone-season variability that would be adequately covered by this 

final rule’s ozone-season NOX variability level (21 percent). Please 

see the “Power Sector Variability Final Rule TSD” for more details. 
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basis for an individual state, the resulting variability in statelevel emissions is difficult to predict. Moreover, because the 

electric generation, transmission, and distribution system in the 

eastern half of the U.S. is highly integrated, year-to-year variation 

in these factors in one state can cause year-to-year variability in 

state-level emissions both in that state and in other states on the 

system. For example, increased demand due to extreme weather or 

increased economic activity in one state can be met through increased 

generation and emissions in a number of states. 

Because these factors can vary year-to-year in every state in 

ways that are difficult to predict and can affect other states, EPA 

maintains that the maximum variability measured in one state for a 

discrete period (2000-2010) is reasonably likely to occur in the 

future in any of the states in the region. Consequently, EPA 

believes that it is reasonable to use the maximum historic percentage 

variability figure as a proxy for the percentage variability that any 

of the states is likely to experience in the future. Although EPA is 

therefore using a uniform percentage figure for variability, EPA 

applies that percentage figure to each state-specific budget so that 

variability in tons of emissions is determined on a state-specific 

basis. That state-specific number is used in determining whether the 

assurance provisions and penalty are triggered in the specific state. 

EPA also believes that it is appropriate to accommodate this 

potential future variability at the state level if and only if it can 

be accommodated without undermining the programs’ beneficial impacts 
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on downwind air quality that eliminate significant contribution to 

nonattainment or interference with maintenance of the NAAQS assessed 

in this rulemaking (see the “Power Sector Variability Final Rule TSD” 

for more information on this analysis). The Transport Rule 

identifies and quantifies, on a state-by-state basis, the emissions 

in each state that significantly contribute to nonattainment or 

interfere with maintenance in another state. This is done by 

analyzing specific air pollution linkages between each upwind state 

and each downwind maintenance or nonattainment receptor. 

Nonetheless, it is clear from the air quality analyses that the air 

quality outcome at a given downwind receptor is a function of the 

cumulative emissions from all upwind states and the receptor’s home 

state. Once the Transport Rule emission reduction requirements are 

implemented in all states subject to the programs, EPA’s analysis 

shows that the impact on a downwind receptor of any single upwind 

state’s year-to-year fluctuation of up to 20 percent in SO2 emissions 

would be so limited as to not disturb that receptor’s ability to 

maintain or attain the NAAQS analyzed in this rulemaking. Therefore, 

to the extent that such variability has been measured in historic 

data in any state subject to the Transport Rule programs, it is 

reasonable to provide for potential future variability in Transport 

Rule states within the scope of what EPA’s analysis shows to preserve 

downwind air quality gains achieved by the Transport Rule programs.

The approach to establishing variability limits in the final 

rule modifies the approach from the proposed rule in two ways. 
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First, EPA is applying only a percentage variability limit to each 

budget in the final rule, whereas the proposed rule applied the 

greater of a percentage or an absolute tonnage variability limit to 

each budget. EPA explained in the proposal that it was necessary to 

impose both a percentage and a tonnage limit due to the inclusion of 

“states with small numbers of units where expected variability would 

be more pronounced in percentage terms” (75 FR 45293). However, the 

states with the smallest numbers of units included at proposal (such 

as Connecticut and the District of Columbia) are not covered by any 

of the final Transport Rule’s programs. In the final rule’s 

variability analysis, Tennessee has the highest measured annual 

variability percentage and Virginia has the highest measured ozoneseason variability percentage. Both of these states have a 

sufficient number of units for the percentage variability findings to 

be representative of variability in all of the Transport Rule states; 

therefore, it is not necessary to impose a tonnage limitation in the 

final rule.

Second, EPA has expanded the historic baseline of the 

variability analysis to consider heat input data from 2000 through

2010, as compared to 2002 through 2008 at proposal, and EPA has also 

expanded the dataset to include all units expected to be covered by 

the final Transport Rule’s programs. EPA received a number of 

comments that the proposal’s variability limits were too stringent in 

part because they relied on too short a historical baseline that 

failed to capture the full extent of long-run year-to-year 
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variability. EPA agrees with these comments and believes that the 

historic baseline modification described above supports variability 

limits in the final rule that are a better approximation of future 

potential year-to-year variability in state-level EGU emissions 

around the budgets as a function of inherent variability in baseline 

state-level EGU operations. EPA believes the 2000 through 2010 

historic baseline supports a more accurate approximation of year-toyear variability in state-level EGU operations than previously 

measured on a 2002 through 2008 baseline.

Some commenters expressed the view that allowing variability 

limits in addition to state budgets undermines the requirements of 

CAA section 110(a)(2)(D)(i)(I) to eliminate significant contribution 

to nonattainment and interference with maintenance of the NAAQS in 

downwind states. EPA disagrees with these comments. As explained 

above, EPA finds that year-to-year variability is an inherent 

characteristic of power sector emissions whether or not such 

emissions are controlled by state budgets; the future year-to-year 

variability is a component of the sector’s emissions baseline before 

emission reductions are required. As done for proposal, EPA has 

analyzed the impact of allowing emissions from upwind states in a 

given year to rise above the budgets but within the variability 

limits allowed in the final rule. This analysis shows that emission 

fluctuations around the budgets but within the variability limits 

will not undermine the downwind air quality gains achieved by the 

implementation of the Transport Rule budgets, and therefore the 
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variability limits cannot be said to undermine the elimination of 

significant contribution to nonattainment or interference with 

maintenance achieved under the Transport Rule programs. Based on 

historical data and projected air quality impacts, the Agency 

believes that states will have sufficient flexibility and room to 

operate within the final rule’s variability limits while addressing 

all emissions identified as significantly contributing to 

nonattainment or interfering with maintenance in other states.

F. Variability Limits and State Emission Budgets: State Assurance 

Levels

As explained above, EPA applied the variability levels on a 

state-by-state basis to calculate specific emission budgets with 

variability limits. The state budget plus the variability limit is 

also called the “state assurance level.” Table VI.F-1 shows final 

state budgets, variability limits, and assurance levels by state for 

SO2 emissions. Table VI.F-2 shows final state budgets, variability 

limits, and assurance levels by state for annual NOX emissions. Table 

VI.F-3 shows final state budgets, variability limits, and assurance 

levels by state for ozone-season NOX emissions.

Table VI.F-1 – State Budgets, Variability Limits, and Assurance 

Levels for SO2 Emissions

Emission Budget 

(tons)

Emission 

Variability Limit 

(tons)

State Emissions 

Assurance Level 

(tons)

2012-

2013

2014 and 

beyond

2012-

2013

2014 and 

beyond

2012-

2013

2014 and 

beyond

Alabama 216,033 213,258 38,886 38,386 254,919 251,644

Georgia 158,527 95,231 28,535 17,142 187,062 112,373
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Illinois 234,889 124,123 42,280 22,342 277,169 146,465

Indiana 285,424 161,111 51,376 29,000 336,800 190,111

Iowa 107,085 75,184 19,275 13,533 126,360 88,717

Kansas 41,528 41,528 7,475 7,475 49,003 49,003

Kentucky 232,662 106,284 41,879 19,131 274,541 125,415

Maryland 30,120 28,203 5,422 5,077 35,542 33,280

Michigan 229,303 143,995 41,275 25,919 270,578 169,914

Minnesota 41,981 41,981 7,557 7,557 49,538 49,538

Missouri 207,466 165,941 37,344 29,869 244,810 195,810

Nebraska 65,052 65,052 11,709 11,709 76,761 76,761

New Jersey 5,574 5,574 1,003 1,003 6,577 6,577

New York 27,325 18,585 4,919 3,345 32,244 21,930

North 

Carolina 136,881 57,620 24,639 10,372 161,520 67,992

Ohio 310,230 137,077 55,841 24,674 366,071 161,751

Pennsylvania 278,651 112,021 50,157 20,164 328,808 132,185

South 

Carolina 88,620 88,620 15,952 15,952 104,572 104,572

Tennessee 148,150 58,833 26,667 10,590 174,817 69,423

Texas 243,954 243,954 43,912 43,912 287,866 287,866

Virginia 70,820 35,057 12,748 6,310 83,568 41,367

West Virginia 146,174 75,668 26,311 13,620 172,485 89,288

Wisconsin 79,480 40,126 14,306 7,223 93,786 47,349

Note: Budgets, limits, and assurance levels apply to each state’s emissions from 

covered sources, as defined by this final rule, only.

Table VI.F-2 – State Budgets, Variability Limits, and Assurance 

Levels for Annual NOX Emissions 

Emission Budget 

(tons)

Emission 

Variability Limit 

(tons)

State Emissions 

Assurance Level 

(tons)

2012-

2013

2014 and 

beyond

2012-

2013

2014 and 

beyond

2012-

2013

2014 and 

beyond

Alabama 72,691 71,962 13,084 12,953 85,775 84,915

Georgia 62,010 40,540 11,162 7,297 73,172 47,837

Illinois 47,872 47,872 8,617 8,617 56,489 56,489

Indiana 109,726 108,424 19,751 19,516 129,477 127,940

Iowa 38,335 37,498 6,900 6,750 45,235 44,248

Kansas 30,714 25,560 5,529 4,601 36,243 30,161

Kentucky 85,086 77,238 15,315 13,903 100,401 91,141

Maryland 16,633 16,574 2,994 2,983 19,627 19,557

Michigan 60,193 57,812 10,835 10,406 71,028 68,218

Minnesota 29,572 29,572 5,323 5,323 34,895 34,895

Missouri 52,374 48,717 9,427 8,769 61,801 57,486

Nebraska 26,440 26,440 4,759 4,759 31,199 31,199

New Jersey 7,266 7,266 1,308 1,308 8,574 8,574

New York 17,543 17,543 3,158 3,158 20,701 20,701
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North 

Carolina 50,587 41,553 9,106 7,480 59,693 49,033

Ohio 92,703 87,493 16,687 15,749 109,390 103,242

Pennsylvania 119,986 119,194 21,597 21,455 141,583 140,649

South 

Carolina 32,498 32,498 5,850 5,850 38,348 38,348

Tennessee 35,703 19,337 6,427 3,481 42,130 22,818

Texas 133,595 133,595 24,047 24,047 157,642 1 57,642

Virginia 33,242 33,242 5,984 5,984 39,226 39,226

West Virginia 59,472 54,582 10,705 9,825 70,177 64,407

Wisconsin 31,628 30,398 5,693 5,472 37,321 35,870

Note: Budgets, limits, and assurance levels apply to each state’s emissions from 

covered sources, as defined by this final rule, only.

Table VI.F-3 – State Budgets, Variability Limits, and Assurance 

Levels for Ozone-Season NOX Emissions

Emissions Budget 

(tons)

Emissions 

Variability Limit 

(tons)

State Emissions 

Assurance Level 

(tons)

2012-

2013

2014 and 

beyond

2012-

2013

2014 and 

beyond

2012-

2013

2014 and 

beyond

Alabama 31,746 31,499 6,667 6,615 38,413 38,114

Arkansas 15,037 15,037 3,158 3,158 18,195 18,195

Florida 27,825 27,825 5,843 5,843 33,668 33,668

Georgia 27,944 18,279 5,868 3,839 33,812 22,118

Illinois 21,208 21,208 4,454 4,454 25,662 25,662

Indiana 46,876 46,175 9,844 9,697 56,720 55,872

Kentucky 36,167 32,674 7,595 6,862 43,762 39,536

Louisiana 13,432 13,432 2,821 2,821 16,253 16,253

Maryland 7,179 7,179 1,508 1,508 8,687 8,687

Mississippi 10,160 10,160 2,134 2,134 12,294 12,294

New Jersey 3,382 3,382 710 710 4,092 4,092

New York 8,331 8,331 1,750 1,750 10,081 10,081

North 

Carolina 22,168 18,455 4,655 3,876 26,823 22,331

Ohio 40,063 37,792 8,413 7,936 48,476 45,728

Pennsylvania 52,201 51,912 10,962 10,902 63,163 62,814

South 

Carolina 13,909 13,909 2,921 2,921 16,830 16,830

Tennessee 14,908 8,016 3,131 1,683 18,039 9,699

Texas 63,043 63,043 13,239 13,239 76,282 76,282

Virginia 14,452 14,452 3,035 3,035 17,487 17,487

West Virginia 25,283 23,291 5,309 4,891 30,592 28,182

Note: Budgets, limits, and assurance levels apply to each state’s emissions from 

covered sources, as defined by this final rule, only.
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See section VII.E for the discussion of how variability limits 

and state assurance levels are used in the implementation of 

assurance provisions for the air quality-assured trading programs. 

G. How the State Emission Reduction Requirements are Consistent with 

Judicial Opinions Interpreting the Clean Air Act

The methodology described in this notice quantifies states’ 

significant contribution to nonattainment and interference with 

maintenance in a manner that is consistent with the decisions of the 

D.C. Circuit. As discussed previously, the D.C. Circuit has issued 

two significant decisions addressing the requirements of 

110(a)(2)(D)(i)(I). The first opinion largely upheld the NOX SIP 

Call, Michigan, 213 F.3d 663, and the second found significant flaws 

in CAIR, North Carolina, 531 F.3d. 896. 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 final 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 rule relies on state-specific data to 

analyze each individual state’s significant contribution, uses air 

quality considerations in addition to cost considerations to identify 

each state’s significant contribution, and gives independent meaning 

to the “interference with maintenance” prong. This methodology is 
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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 emission 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 rule, EPA uses a first step similar to that used in 

CAIR to identify the states with relatively large contributions. 

However, in contrast to CAIR, it then uses a state-specific analysis. 

Instead of identifying a single emission level that could be achieved 

by the application of highly cost effective controls in the region, 

EPA determines, on a state-by-state basis, what reductions could 

effectively be achieved by sources in each 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, emission budgets based on the 

reductions achievable at a particular cost per ton in that particular 
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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 
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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-costeffective.” 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 “gave no independent significance to the 
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‘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 V.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 statespecific basis, that the emissions prohibited in the FIPs are either 
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part of or constitute the state’s significant contribution to 

nonattainment and interference with maintenance. Thus, elimination 

of these emissions will, at a minimum, make measurable progress 

towards satisfying the section 110(a)(2)(D)(i)(I) prohibition on 

significant contribution to nonattainment and interference with 

maintenance.

VII. FIP Program Structure to Achieve Reductions

A. Overview of Air Quality-Assured Trading Programs

EPA is finalizing an air quality-assured trading remedy that is 

substantially similar to the preferred trading remedy presented in 

the proposal. Key differences from the preferred trading remedy in 

the proposal include: 

 Recalculated state budgets and variability limits (i.e., state 

assurance levels) based on updated modeling;

 Simplified variability limits for 1-year application only;

 Revised allocation methodology for existing and new units and 

revised new unit set-asides for new units in Transport Rule 

states and new units potentially locating in Indian country;

 Changed start of assurance provisions to 2012 and increased 

assurance provision penalties; and

 Removed opt-in provisions.

In the final rule, as in the proposed rule, EPA is promulgating 

FIPS to require SO2 and NOX reductions from power plants in 
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jurisdictions55 that contribute significantly to nonattainment in, or 

interfere with maintenance by, a downwind area with respect to the 

1997 ozone NAAQS, the 1997 annual PM2.5 NAAQS, and/or the 2006 24-hour

PM2.5 NAAQS. These FIPs establish state-specific emission control 

requirements using state budgets starting in 2012, with a second 

phase of SO2 reductions in some states in 2014. Section IV explains 

EPA’s authority to issue FIPs. 

The air quality-assured trading remedy in the final rule allows 

interstate trading to account for variability in the electricity 

sector, but also includes assurance provisions to ensure that the 

necessary emission reductions occur within each covered state. The 

assurance provisions restrict EGU emissions within each state to the 

state’s budget plus the variability limit and ensure that every state 

is making reductions to eliminate the significant contribution to 

nonattainment and interference with maintenance that EPA has 

identified. While EPA proposed to impose these assurance provisions 

starting in 2014, the final rule implements these provisions starting 

in 2012 (see section VII.E of this preamble). Additionally, the 

final FIPs include penalty provisions adequate to ensure that the 

state budget with the variability limit will not be exceeded.

 

55 Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Iowa, 

Kansas, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 

Mississippi, Nebraska, New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West 

Virginia, and Wisconsin. As discussed in section III, in a separate 

notice, EPA is proposing to include Iowa, Kansas, Michigan, Missouri, 

Oklahoma, and Wisconsin in the ozone-season NOX requirements.
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In the final rule, as in the preferred trading remedy discussed 

in the proposed rule, state-specific emission budgets without the 

variability limits are used to determine the number of emission 

allowances allocated to sources in each state. An EGU source is 

required to hold one SO2 or one NOX allowance, respectively, for every 

ton of SO2 or NOX emitted during the control period. Banking of 

allowances for use or trading in future years is allowed. 

The final rule establishes four interstate trading programs, 

each 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 SO2 Group 1) that need to make larger 

reductions to eliminate their significant contribution, while the 

second is for sources in states (referred to as SO2 Group 2) that need 

to make smaller reductions. A source in a Group 1 state can only use 

SO2 allowances allocated to Group 1 states for compliance with the SO2

trading program. A source in a Group 2 state can only use SO2

allowances allocated to Group 2 states for compliance with the SO2

trading program. For compliance in the annual NOX and ozone-season 

NOX trading programs respectively, sources may use annual NOX and 

ozone-season NOX allowances allocated for any state, even if that 

state is in a different group for SO2 than the source’s state. Four 

sets of new emission allowances based on the new state-specific 

budgets without variability are allocated to sources, one set for 

each of the four trading programs. Each state has the option of 

replacing these FIPs with state rules. EPA believes that this remedy 
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meets the concerns raised by the Court in the 2008 North Carolina

decisions which remanded CAIR to EPA.

In the proposed rule, EPA took comment on all aspects of the 

preferred trading remedy and on two alternative regulatory options: 

(1) intrastate trading; and (2) direct control. EPA also took 

comment on a trading ratios approach.

Comments on the Preferred Trading Remedy: The great majority of 

public comments supported the preferred trading remedy. Most of 

these commenters voiced their support for the broadest possible 

trading mechanism because it allows for the most cost-effective 

implementation of any emission controls. Commenters noted that 

flexibility is always needed in the early years of new programs. 

Further, commenters favoring the preferred remedy agreed with EPA 

that, by using state-specific control budgets and allowing for 

interstate trading, the preferred remedy provided electricity 

generators the flexibility to undertake the most cost-effective 

reductions while assuring that the resulting reductions occur within 

the individual states.

Some commenters that supported the preferred remedy felt that, 

while not ideal, the interstate trading remedy was preferable to the 

alternative options of intrastate trading or direct control. Many 

commenters that supported the preferred remedy felt that the 

intrastate trading remedy and direct control remedy options offer 

minimal flexibility from a compliance perspective. They stated that 
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this lack of flexibility would unnecessarily increase the cost of 

emission reductions. 

Other commenters who generally support the preferred remedy 

cited concerns about the level of complexity in the assurance 

provisions. One commenter surmised that the preferred option creates 

significant risk where a company could unexpectedly find itself in a 

noncompliance situation due to the after-the-fact variability 

analysis. Another said that the rule’s features needlessly reduce 

the system’s efficiency and increase complexity. These commenters 

generally preferred unlimited trading, noting that EPA has proven 

success with Title IV, the NOX SIP Call, and CAIR unlimited interstate 

trading programs and that allowing unrestricted interstate trading 

would increase flexibility to meet reduction goals and minimize 

increases in power costs. 

EPA is finalizing the preferred trading remedy for the following 

reasons. EPA believes this approach is the most cost-effective and 

practical way to comply with the Court decision in North Carolina to 

ensure that all emissions in a given state that EPA has identified as 

significantly contributing to downwind nonattainment or interfering

with maintenance are eliminated. The vast majority of public 

commenters agree. In addition, this approach provides the most 

flexibility for sources while meeting the Clean Air Act requirements 

and protecting public health. As a result, potential innovations and 

resulting cost savings are more likely to be found and implemented. 

Based on historical experience (see the Transport Rule proposal, 75 
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FR 45315), EPA has shown that the results offered by a flexible 

trading approach (e.g., flexible compliance choices, incentives to 

reduce emissions early and in the highest emitting areas, 100 percent 

compliance with requirements) are substantial. A large number of 

commenters have corroborated this assessment. As summarized in the 

proposal, EPA believes that the preferred trading remedy will allow 

source owners to choose among several compliance options to achieve 

required emission reductions in the most cost-effective manner, such 

as installing controls, changing fuels, reducing utilization, buying 

allowances, or any combination of these actions. Interstate trading

with assurance provisions provides additional regulatory flexibility 

that promotes the power sector’s ability to operate as an integrated, 

interstate system and to provide electric reliability. 

Comments on Intrastate Trading: A few commenters favored the 

first alternative, intrastate trading. One commenter who favored 

intrastate trading stated that many power plants have avoided 

investment in pollution controls by buying allowances from other 

plants, affecting local air quality improvement. EPA notes that this 

Transport Rule aims to address emissions from one state that 

significantly contribute to nonattainment or interfere with 

maintenance of certain NAAQS in other states. Local air quality 

issues are directly addressed by other provisions in the Clean Air 

Act. 

Several commenters raised concerns about the intrastate trading 

approach. Some stated, as EPA noted in the proposal, that the 
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intrastate trading option would be more resource intensive, more 

complex, less flexible, and potentially more susceptible to market 

manipulation than the other options. In addition, some commenters 

felt that this alternative would provide less flexibility to ensure 

electric reliability than the preferred approach, resulting in 

greater private costs to the power sector and greater social costs 

for consumers. 

EPA is not finalizing the intrastate trading option for the 

following reasons. As EPA expressed in the proposal and as 

commenters have agreed, the intrastate trading option would be more 

resource intensive (both for EPA and for sources), more complex, less 

flexible, and potentially more susceptible to market manipulation 

than the preferred trading approach that EPA is finalizing. The 

intrastate trading option would be more costly and less transparent 

due to the large number of trading programs that would be operated 

simultaneously and the large number of annual auctions that would be 

held every year to address the issues of market power within states. 

This option would also result in a greater burden for participants 

operating EGUs in multiple states. 

Comments on Direct Control Option: Several commenters favored 

the second alternative, direct control. One commenter stated that 

direct control -- allowing no trading -- was the option best aligned 

with the 2008 Court decisions. EPA disagrees with this comment for 

the reasons given below and because, as explained in this rule, EPA 
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believes the air quality-assured trading remedy finalized today is 

consistent with the decisions of the D.C. Circuit in North Carolina. 

Some commenters, who support direct control, voiced concerns 

that the other emission trading approaches would disadvantage poor 

and minority communities or allow increased emission impacts in 

neighborhoods near power plants. EPA notes that a direct control 

approach would not require controls on all plants in a state, but 

only on a sufficient number to address the transport requirements 

under section 110(a)(2)(d)(i)(I) that this rule addresses, and 

therefore would not necessarily mandate controls on each neighborhood 

power plant.

In addition, EPA has conducted an analysis of the effects of the 

Transport Rule on environmental justice and other vulnerable 

communities. We concluded that, similar to our experience with the 

Acid Rain Program,56 many environmental justice communities are 

expected to see large health benefits, and none are expected to 

experience any disbenefits, from implementing an air quality-assured

trading program. The results of this analysis are presented in 

section XII of this preamble and Chapter 5 of the RIA for this rule. 

In addition, the CAA provides flexibility for state and local 

authorities to impose stricter limits on sources to address specific 

local air quality concerns. Such limits are independent of the 

 

56 See http://www.epa.gov/airmarkets/resource/docs/ejanalysis.pdf and 

Ringquist, Evan J. 2011. “Trading Equity for Efficiency in 

Environmental Protection? Environmental Justice Effects from the SO2

Allowance Trading Program.” Social Science Quarterly 92(2):297-323
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requirements in this rule, and compliance with Transport Rule 

requirements in no way excuses a source from complying with other CAA

or state law requirements.

Several commenters raised concerns with the direct control 

approach. One commenter felt that issues with electricity market 

reliability could occur during high electricity demand periods if 

sources ceased operations due to approaching their emission rate 

limitations under a direct control remedy. Another commenter was 

concerned that applying emission rates under a direct control remedy 

to small municipal units would cause disproportionate impacts on 

power plants where pollution control is more expensive. Other 

commenters cited concerns that EPA’s proposed within-state companywide averaging provision in the direct control proposed alternative 

(designed to allow some flexibility for sources) would place 

companies with fewer units at a disadvantage compared to companies 

with more units. EPA generally agrees with the commenters concerns 

and has decided not to finalize the direct control remedy for the 

following reasons. EPA modeling projects that the direct control 

alternative would result in fewer emission reductions and higher 

costs compared to the air quality-assured trading remedy. EPA 

analysis indicates that it is not necessary to implement a direct 

control approach in order to protect vulnerable and sensitive 

populations or environmental justice communities. Also, the direct 

control approach would result in fewer compliance options because a 

direct control approach would directly regulate individual sources by 
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setting unit-level emission rate limits. This lack of flexibility 

could lead to potential increases in reliability risks in the 

electric power system and fewer opportunities for potential 

technological innovations that reduce emissions further and/or lower 

costs. For these reasons, EPA believes that this approach is 

inferior to the air quality-assured trading remedy. 

Other Comments: A handful of commenters mentioned the trading 

ratios approach, though none favored it as a viable alternative. One 

commenter said the trading ratios approach was not consistent with 

CAA section 110(a)(2)(D) requirements that reductions in emissions 

occur in particular geographic locations. Other commenters agreed 

that it was administratively unworkable and would be difficult to 

implement due to the complexity and variety of meteorological 

conditions. EPA generally concurs with the commenters. In the 

proposal, EPA noted that it would not be possible under this 

approach, as contemplated, 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 requested comment on whether a 

ratios trading program could be designed to provide such legal 

assurances. Of the few comments received, none offered such a 

solution. For these reasons, EPA is not finalizing this approach.

Some commenters offered additional suggestions, such as: 

unrestricted trading; using different authorities in the CAA to 

address interstate transport such as section 110(k)(5) and section 
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126; and an approach that would replace the assurance provisions by a 

system using both emission allowances usable (as well as bankable) in 

any state and assurance allowances usable (but not bankable) in only 

the state for which they would be issued. While EPA appreciates the 

thoughtful and constructive comments, we did not find any of these 

suggestions improved our ability to address interstate transport 

under CAA section 110(a)(2)(D)(i)(I), in line with the Court 

decision, in an administratively practical way. 

Several commenters liked the idea of establishing unit-by-unit 

short-term and long-term performance standards/emission rates but 

suggested adding an overlaid cap and trade program. EPA believes the 

air quality-assured trading remedy finalized today is consistent with 

the decisions of the Court in North Carolina and will ensure the 

reductions necessary to meet statutory requirements. 

For the 2012-2013 period, EPA took comment on whether the 

assurance provisions are needed, since the state-specific budgets 

would be based on known air pollution controls and the penalty 

provisions would be adequate to ensure that the budget, including a 

variability limit, would not be exceeded. Further, EPA proposed to 

use two variability limits: a 1-year limit, based on the year-toyear variability in emissions relative to the proposed budgets; and a 

3-year limit based on the variability in a 3-year average relative to 

the proposed budget.

Based on comments on the assurance provisions (see section VII.E 

of this preamble) and variability limits (see section VI.E.2 of this 
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preamble), EPA is finalizing the Transport Rule with state budgets 

plus variability limits and assurance provisions starting in 2012 for 

all of the trading programs. EPA sees an immediate need to ensure 

that emissions within a state do not exceed the state budget plus the 

variability limitation in order to comply with the Court’s opinion. 

Further, commenters stated that the 3-year variability limit

increased costs and unnecessarily complicated the trading programs. 

As explained in section VI.E.2, EPA is finalizing the 1-year 

variability limit starting in 2012, but not the 3-year limit.

B. Applicability

The applicability provisions in the final rule are, except as 

discussed herein, essentially the same as in the proposed rules and 

for each of the Transport Rule trading programs.

Under the general applicability provisions of the proposed rule, 

the Transport Rule trading programs would cover fossil-fuel-fired 

boilers and combustion turbines serving –- on any day starting 

November 15, 1990 or later -- 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.

EPA requested comment on whether a more recent year should be 

used instead. The proposed use of the November 15, 1990 date was 

consistent with the use of 1990 as the beginning of the historical 

period for which owners and operators would generally be required to 

have information about their units for purposes of determining 
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whether the units were covered by the Transport Rule trading 

programs. Because unit information is generally compiled and 

retained on a calendar year basis, EPA believes that, for the general 

applicability provisions, it is preferable to use January 1, rather 

than November 15. In determining which year should be used as the 

reference year in the general applicability provisions, EPA considers 

several factors.

First, in order for owners and operators, and EPA, to be able to 

determine which units are subject to the Transport Rule trading 

programs, EPA believes that the reference year should not be so far 

in the past that the unit information necessary to make applicability 

determinations is not readily available. This particularly becomes 

an issue in cases of older units that have changed ownership over 

time. EPA found, in making some applicability determinations under 

the CAIR trading programs, that some older units with ownership 

changes had difficulty obtaining information back as far as twenty or 

more years. Using January 1, 1990 as the reference date in the 

general applicability provisions could effectively require some 

owners and operators to retain unit information going back as far as 

20 years. As a point of contrast, under the title V permitting 

rules, owners and operators are generally required to retain data for 

5 years. See 40 CFR 70.6(a)(3)(B). 

Second, EPA also believes that the reference year used in the 

applicability provisions should be far enough in the past that the 

unit information on which applicability determinations are based 
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provides a full picture of the nature of the unit and its operations 

over time, such as the types of fuels combusted at the unit and 

whether the unit has produced electricity for sale. 

Third, EPA considers whether selecting a different reference 

year for the applicability provisions than the one in the proposed 

rule dramatically changes what units will be covered by the Transport 

Rule trading programs. In this case, EPA believes, based on 

available information about the units potentially subject to the 

Transport Rule, that using a somewhat later year than the one in the 

proposed rule will likely have little effect on what units are 

covered. Balancing these factors, EPA concludes that it is 

reasonable to use January 1, 2005, rather than November 15, 1990, in 

the general applicability provisions in the final rule.

In the final rule, EPA is taking the same approach with regard 

to defining whether a boiler or combustion turbine is considered to 

be “fossil-fuel-fired” as the one used in the proposal. Under the 

proposed rule, a unit was considered to be “fossil-fuel-fired” if it 

combusts any amount of fossil fuel at any time in 1990 or later. For 

the same reasons that EPA decided to use January 1, 2005 in the 

general applicability provisions, and in order to have a consistent 

reference year in all applicability-related provisions, the final 

rule defines a “fossil-fuel-fired” unit as one that combusts any 

amount of fossil fuel in 2005 or later. 

EPA notes that the final Transport Rule allows a state to submit 

a SIP revision (an abbreviated or full SIP) under which the state may 
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-- in addition to making certain types of changes concerning 

allowance allocations in the Transport Rule trading programs –-

expand the general applicability provisions of the Transport Rule NOX

Ozone Season Trading Program to cover fossil-fuel-fired boilers and 

combustion turbines serving –- at any time starting January 1, 2005 

or later -– a generator with a nameplate capacity as low as 15 MWe 

producing power for sale. The exemptions, discussed below, for 

cogeneration units and solid waste incineration units still will 

continue to apply.

Cogeneration unit exemption. Under the final rule (as well as 

the proposed rule) certain cogeneration units or solid waste 

incinerators are exempt from the FIP requirements. In particular, 

the final rule includes an exemption for a unit that qualifies as a 

cogeneration unit throughout the later of 2005 or the first 12 months 

during which the unit first produces electricity and continues to 

qualify through each calendar year ending after the later of 2005 or 

that 12-month period and that meets the limitation on electricity 

sales to the grid. In order to meet the definition of “cogeneration 

unit” in the final rules, a unit (i.e., a fossil-fuel-fired boiler or 

combustion turbine) must be a topping-cycle or bottoming-cycle that 

operates 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 
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energy. A topping-cycle unit is a unit where the sequential use of 

energy results in production of useful power first and then, through 

use of reject heat from such production, in production of useful 

thermal energy. A bottoming-cycle unit is a unit where the 

sequential use of energy results in production of useful thermal 

energy first and then, through use of reject heat from such 

production, in production of useful power. In order to qualify as a 

cogeneration unit, a unit also must meet certain efficiency and 

operating standards. 

In the proposed rule, a unit would have to qualify as a 

cogeneration unit and meet the limitation on electricity sales 

starting the later of 1990 or the year when the unit begins 

operating. EPA requested comment on whether a more recent year 

should be used. For the reasons discussed above concerning the 

reference year used in the general applicability provisions and in 

order to have a consistent reference year in all applicabilityrelated provisions, EPA concludes that it is reasonable to use 2005, 

rather than 1990, in the cogeneration unit exemption provisions in 

the final rule. Consequently, the final rule provides that the 

requirements to qualify as a cogeneration unit and to meet the 

electricity sales limitation start no earlier than 2005.

In the final rule, EPA also clarifies that the electricity sales 

limitation under the exemption is applied in the same way whether a 

unit serves only one generator or serves more than one generator. In 

both cases, the total amount of electricity produced annually by a 
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unit and sold to the grid cannot exceed the greater of one-third of 

the unit’s potential electric output capacity or 219,000 MWhr. This 

is consistent with the approach taken in the Acid Rain Program (40 

CFR 72.7(b)(4)), where the cogeneration unit exemption originated. 

EPA believes that this clarification is needed to ensure that a unit 

serving, for example, two generators would not have a limit on sales 

of electricity to the grid that would be different (i.e., twice as 

high) from the limit for a unit serving only one generator with the 

same total nameplate capacity as the first unit’s two generators.

EPA also took comment on whether efficiency standards should be 

applied on a system-wide basis to bottoming-cycle units (where useful 

thermal energy is produced before useful power is produced), as they 

are for topping-cycle units (where useful thermal energy is produced 

after useful power) and whether to exclude, from the requirement to 

meet the operating and efficiency standards, calendar years during 

which a cogeneration unit does not operate at all. Several 

commenters argued EPA should apply efficiency standards to both types 

of units. EPA agrees that applying efficiency standards on a systemwide basis to both bottoming-cycle and topping-cycle units is 

reasonable because EPA sees no technical reason to distinguish 

between the two types of units in this instance. EPA further agrees 

with commenters that excluding calendar years in which the 

cogeneration unit does not operate at all, i.e., does not combust any 

fuel, from the requirements to meet operating and efficiency 

standards is also reasonable. For such a year, the unit would not 
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produce any useful thermal energy or useful power and therefore could 

not meet the minimum output requirements in the operating and 

efficiency standards, but the unit also would not have any emissions. 

For these reasons, the final rule expressly provides that the 

operating and efficiency standards do not have to be met for a 

calendar year throughout which a unit did not operate at all. 

Solid waste incineration unit exemption. The final rule also 

includes an exemption for a unit that qualifies as a solid waste 

incineration unit during the later of 2005 or the first 12 months 

during which the unit first produces electricity, that continues to 

qualify throughout each calendar year ending after the later of 2005 

or that 12-month period each year thereafter, and that meets the 

limitation on fossil-fuel use. In contrast, the exemption for solid 

waste incineration units in the proposed rule distinguished between 

units commencing operation before January 1, 1985 and those 

commencing operation on or after that date. A unit commencing 

operation before January 1, 1985 would be exempt if it qualified as a 

solid waste incineration unit starting the later of 1990 or the year 

when it began producing electricity and its average annual fuel 

consumption of non-fossil fuels exceeded 80 percent of total heat 

input during 1985-1987 and during any three consecutive calendar 

years after 1990. A unit commencing operation on or after January 1, 

1985 would be exempt if it qualified as a solid waste incineration 

unit starting the later of 1990 or the year when it began producing 

electricity and its average annual fuel consumption of non-fossil 
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fuel exceeded 80 percent of total heat input for the first 3 calendar 

years of operation and for any 3 consecutive calendar years 

thereafter. 

In the proposal, EPA requested comment on whether it would 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. For the reasons discussed above concerning the 

reference year used in the general applicability provisions and in 

order to have a consistent reference year for all applicabilityrelated provisions, EPA concludes that it is reasonable to use 2005, 

rather than 1990, in the solid waste incineration unit exemption in 

the final rule. In particular, EPA notes that the proposed 

provisions for units commencing operation before January 1, 1985 and 

for units commencing operation on or after January 1, 1985 could 

require some owners and operators to retain unit information going 

back more than 20 years before the promulgation of this final rule. 

Further, EPA believes that removing the distinction between units 

commencing operation during these two periods, and referencing 

somewhat later years as the earliest years for which information on 

fossil-fuel consumption is required, will result in the exemption 

still being based on sufficient data to provide a full picture of the 

nature and operation of the units involved. EPA also believes, based 

on available information about the units potentially subject to the 

Transport Rule, that this approach will not significantly change 
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which units qualify for the exemption. Consequently, the final rule 

removes the distinction based on whether a solid waste incineration 

unit commences operation before January 1, 1985 or on or after 

January 1, 1985. In order to be exempt, the unit must qualify as a 

solid waste incineration unit during the later of 2005 or the first 

12 months during which the unit first produces electricity, must 

continue to qualify throughout each calendar year ending after the 

later of 2005 or that 12-month period, and must meet the limitation on 

fossil-fuel use on a 3-year average basis during the first 3 years of 

operation starting no earlier than 2005 and every 3 years of 

operation thereafter. 

Opt-in units. EPA is not finalizing the opt-in provisions that 

were discussed in the Transport Rule proposal. EPA proposed opt-in 

provisions to allow non-covered units to voluntarily opt in to any of 

the proposed Transport Rule trading programs and receive allocations 

reflecting 70 percent of the unit’s emissions before opting in. 

These allowances were above the state-specific budgets developed 

under the Transport Rule to eliminate a state’s significant 

contribution to nonattainment and interference with maintenance. In 

theory, an opt-in unit that makes reductions below its baseline and 

sells the freed-up allowances is effectively substituting its new, 

lower-cost reductions for higher-cost reductions otherwise required 

by a covered EGU, with the result that the state’s significant 

contribution is still eliminated but at a lower total program cost.
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EPA notes that theoretical benefits anticipated from allowing 

opt-ins did not materialize in prior trading programs with opt-in 

provisions. The Acid Rain Program has about 23 opt in units; the NOX

Budget Trading Program had five opt-in units; and no units opted into 

the CAIR programs. As a group, these opt-in units neither eased the 

achievement of required emission reductions in past trading programs, 

nor reduced overall program costs.

In the proposal, EPA requested comment on the opt-in 

provisions, specifically regarding: what are the benefits of and 

concerns about including opt-in provisions; how to ensure units are 

not credited for emission reductions the units would have made 

anyway; whether the proposed 30 percent reduction (i.e., application 

of the 70 percent multiplier to baseline emissions) or some other 

percentage reduction, or no reduction, should be applied to the 

baseline emission rate used in determining allocations; and whether 

any additional percentage reduction (such as 45 percent) should be 

applied to SO2 Group 1 opt-in units in Phase II to reflect the 

stricter limits for covered units.

Some commenters argued that increasing the Transport Rule 

budgets for opt-ins would undermine the goal of CAA section 

110(a)(2)(D)(i)(I) to eliminate a state’s significant contribution to 

nonattainment and interference with maintenance. One commenter 

stated that it does not favor allowing sources that are not subject 

to the emission reduction requirements to be issued allowances that 

would increase the overall state emission budgets, due to the 
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uncertainty that any reductions made by such units would be surplus, 

verifiable, permanent and enforceable. This could compromise the 

integrity of the EGU emission reduction requirements of the Transport 

Rule and jeopardize assurance that a state’s significant contribution 

would be eliminated, as required by the Court in North Carolina. 

Other commenters claim that, while no cheap tons are available from 

non-EGUs and EPA is right not to require non-EGU reductions, EPA 

should nonetheless allow non-EGUs to choose voluntarily to be covered 

by opting in.

As mentioned previously, the final Transport Rule does not 

include any opt-in provisions either in the FIPs or in the provisions 

allowing modification or replacement of the FIPs through submission 

of trading program provisions in SIPs. EPA has several reasons for 

not adopting provisions to allow opt-in units. First, as mentioned 

above, historically, very few units have opted in. As of 2010, 28 

units out of more than 4,700 covered units (23 units out of a total 

of about 3,600 covered units in the Acid Rain Program and 5 units out 

of a total of about 2,600 covered units in the NOX SIP Call) have 

opted in to EPA trading programs over the past 15 years. In the Acid 

Rain Program, 3 of the units opted in and then, effective for 2005, 

opted out. Four of the units opted in, immediately shut down, and 

continue to receive allowance allocations. Four of the units opted 

in and continue to operate and receive allowance allocations. 

Finally, 12 of the units opted in, after CAIR was finalized, in order 

to receive allowances usable for compliance in the CAIR SO2 trading 
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program. Because CAIR will be replaced by this Transport Rule, EPA 

anticipates that these 12 units will opt out of the Acid Rain 

Program. In the NOX Budget Trading Program, 3 plants with 5 opt-in 

units received allocations between 2003 and 2008. 

Moreover, EPA has determined that the inclusion of opt-in units 

in the Transport Rule trading programs would undermine the rule’s 

objective of addressing emissions in each state that significantly 

contribute to nonattainment or interfere with maintenance in other 

states. As explained above, EPA has established budgets plus 

variability limits that states must meet to ensure that the 

significant contribution to nonattainment and interference with 

maintenance identified by EPA is addressed. If EPA were to allow 

opt-ins, and if any opt-in unit were to receive an allocation of 

allowances for emissions that would be reduced even if the units did 

not opt in, then the inclusion of that opt-in unit in the program 

would allow the sources covered by the Transport Rule to emit in 

excess of the budget plus variability limit with no new, offsetting 

reduction in emissions. For example, after a unit would opt in, 

process or fuel changes made for economic reasons (rather than due to 

any regulatory requirements), or installation of new emission 

controls or fuel-switching conducted to meet future, non-Transport 

Rule regulatory requirements, could result in emission reductions 

that would have occurred “anyway” (i.e., even if the unit had not 

opted in), and the opt-in unit would be allocated allowances for the 

portion of its baseline emissions that would be removed by these 
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“anyway” reductions. Allocations above the cap to opt-in units 

making “anyway” emission reductions would convert these reductions 

into extra allowances (i.e., authorizations to emit) usable by 

covered EGUs to meet their requirements to hold allowances for 

emissions. Because the extra EGU emissions authorized by these extra 

allowances would not be offset by any new emission reductions by the 

opt-in units, this could threaten a state’s ability to eliminate the 

significant contribution to nonattainment and interference with 

maintenance identified by EPA in the final rule. Also, opt-in units, 

which are allocated allowances outside the state budget for covered 

units, could increase the possibility that a state’s total emissions 

would exceed the state budget plus variability and thus that the 

assurance provisions would be triggered.

This problem of allocating allowances for emissions that would 

have been reduced anyway is illustrated by the recent promulgation of 

the final rule, National Emission Standards for Hazardous Air 

Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters (76 FR 15608 (March 21, 

2011))(“ final Boiler MACT rule”), which requires certain industrial, 

commercial, and institutional boilers to meet maximum achievable 

control technology (MACT) standards for emissions of specified 

hazardous air pollutants, such as hydrogen chloride (HCL) and mercury 

(Hg). Some of the control technologies that can be used to meet 

these standards will also provide significant reductions of SO2

emissions. For example, a boiler may use a wet scrubber or the 
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combination of a dry sorbent injection system and a fabric filter 

(among other options) to meet the applicable HCL standard or may use 

a wet scrubber or a combination of activated carbon injection and a 

fabric filter (among other options) to meet the applicable Hg 

standard. See 76 FR 15614 (describing testing and compliance 

requirements when such controls are used to meet these standards); 

and Memo from Brian Shrager to Amanda Singleton and Graham Gibson, 

Revised Methodology for Estimating Cost and Emissions Impacts for 

Industrial, Commercial and Institutional Boilers and Process Heaters 

National Emissions Standards for Hazardous Air Pollutants — Major 

Source (February 11, 2011), Document ID EPA-HQ-OAR-2009-0491-4036 

(section 3.1, describing control options for HCL and Hg control). In 

fact, EPA estimated that the new standards would result in emission 

reductions of not only the hazardous air pollutants directly subject 

to the standards, but also in other air pollutants such as SO2. 

Specifically, EPA projected that compliance with the final Boiler 

MACT rule standards will result in about 431,000 tons of annual SO2

reductions from existing boilers subject to the final Boiler MACT 

rule. This will comprise on average about a 46 percent reduction in 

SO2 emissions for this group of boilers. Coal- and oil-fired boilers 

-- which are the boilers likely to have the most uncontrolled SO2

emissions and so would be the most likely types of units to consider 

opting into the Transport Rule trading programs if opting-in were 

allowed -- are projected to reduce about 409,000 tons of annual SO2 as 

a result of complying with the final Boiler MACT rule, or about a 50 
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percent reduction in SO2 emissions. See Memo from Brian Shrager to 

Amanda Singleton and Graham Gibson, Appendix B-1, (where column CE 

represents baseline SO2 emissions and column CH represents SO2

reductions resulting from the final Boiler MACT rule compliance). 

The amount of offsetting SO2 increases projected to result from final 

Boiler MACT rule compliance, e.g., from additional fuel being 

combusted to generate electricity to operate emission controls, is 

minor. See 76 FR 15651 (Table 4) and 15653 (showing projected total 

SO2 reductions for all boilers and process heaters of about 442,000 

tons and net SO2 reductions of about 440,000 tons). 

Consequently, a boiler subject to the final Boiler MACT rule may 

install a wet acid gas scrubber or a bag house in order to meet the 

HCL or Hg standard applicable to boilers under the final Boiler MACT 

rule and thereby achieve SO2 emission reductions. If that boiler were 

to opt in to one of the Transport Rule SO2 trading programs during the 

year before installing these controls to comply with the final Boiler 

MACT rule, then the boiler would be allocated allowances for the 

unit’s current tons of SO2 emissions and would not need to use these 

allowances for compliance under the Transport Rule once the final 

Boiler MACT-related controls were installed. The allowances 

allocated to the boiler would be additional allowances above the 

Transport Rule trading budget for the state where the boiler was 

located. As a result, the boiler would have freed-up allowances 

above the state trading budget that represent reductions that the 

boiler would have made anyway (i.e., even if the boiler had not opted 
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in) and that could be sold to EGUs covered by the Transport Rule. In 

effect, the opting-in of the boiler would result in the conversion of 

the boiler’s SO2 reductions from the final Boiler MACT rule into 

increased emissions above the state trading budget from EGUs subject 

to the Transport Rule. 

Commenters addressed this issue. For instance, one commenter 

suggested that SO2 reductions made by a boiler under the final Boiler 

MACT rule should be eligible for opt-in provision allowances under 

the Transport Rule trading programs. Another commenter stated that, 

given the uncertainty that reductions made by opt-in units would be 

surplus, verifiable, permanent, and enforceable, opt-in provisions 

could compromise the integrity of the EGU emission reductions.

For the reasons explained above, EPA agrees with the latter 

commenter. Further, EPA notes that none of the commenters supporting 

adoption of the opt-in provisions suggested any revision to the 

proposed opt-in provisions that would address this problem. While 

the proposed opt-in provisions would limit an opt-in unit’s 

allocation for a control period by calculating the allocation using 

the lesser of the unit’s pre-opt-in SO2 emission rate or the most 

stringent SO2 emission rate applicable in that control period, this 

would not address SO2 rate reductions that are not directly required 

by the final Boiler MACT rule but that are a secondary result of 

using and operating certain emission controls installed to comply 

with the HCL or Hg standards under the final Boiler MACT rule. 

Because the secondary SO2 reductions will vary depending on the type 
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of controls installed and on the extent to which the controls are 

used, and a boiler may use a combination of emission controls and 

other approaches to reduce HCL or Hg emissions (such as fuel 

switching), EPA believes that it is highly unlikely that opt-in 

provisions could prevent allocation for “anyway” emission reductions 

resulting from compliance with the final Boiler MACT rule. EPA 

therefore believes that the final Boiler MACT rule provides a 

concrete example of why adoption of opt-in provisions could undermine 

the rule’s objective of addressing emissions in each state that 

significantly contribute to nonattainment or interfere with 

maintenance in other states. EPA notes that the final Boiler MACT 

rule, of course, is simply one example of how allocations for 

“anyway” reductions could occur and undermine the statutory 

requirements of the Transport Rule.

C. Compliance Deadlines

1. Alignment with NAAQS Attainment Deadlines

The compliance dates in the final Transport Rule are aligned 

with the attainment deadlines for the relevant NAAQS and consistent 

with the charges given to EPA by the Court in North Carolina. EPA 

proposed to require, and the final rule requires, compliance by 2014 

with an initial phase of reductions in 2012.57 Sources are required 

 

57

 For the annual programs, sources are required to have, by March 1, 

2013, sufficient allowances in their accounts to cover their 2012 

emissions. For the ozone-season program, they must have allowances 

in their accounts by December 1, 2012 to cover 2012 ozone-season 

emissions. The state budgets which determine the number of 
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to comply with annual SO2 and NOX requirements by January 1, 2012 and 

January 1, 2014 for the first and second phases, respectively. 

Similarly, sources are required to comply with ozone-season NOX

requirements by May 1, 2012, and by May 1, 2014. In selecting these 

dates, EPA was mindful of the NAAQS attainment deadlines which 

require reductions as expeditiously as practicable and no later than 

specified dates (see 42 U.S.C. § 7502(a)(2)(A) (general attainment 

dates); 42 U.S.C. § 7511(a)(1) (attainment dates for ozone 

nonattainment areas)), and also mindful of the court’s instruction to 

“decide what date, whether 2015 or earlier, is as expeditious as 

practicable for states to eliminate their significant contributions 

to downwind nonattainment.” North Carolina, 531 F.3d at 930.

1997 PM2.5 NAAQS Attainment Deadlines. For all areas designated 

as nonattainment with respect to the 1997 PM2.5 NAAQS, the deadline 

for attaining that standard is as expeditious as practicable but no 

later than April 2010 (5 years after designation), with a possible 

extension to no later than April 2015 (10 years after designation).58 

 

allowances allocated to units in each state become more stringent for 

some states in 2014.

58 Section 172(a)(2) of the Clean Air Act provides that the attainment 

dates for areas designated nonattainment with a NAAQS shall be the 

date by which attainment can be achieved as expeditiously as 

practicable, but no later than 5 years from the date of designation. 

This section also allows the Administrator to extend the attainment 

date to the extent she 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 1997 
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Many areas have already come into attainment by the April 2010 

deadline due in part to reductions achieved under CAIR. The fact 

that the 2010 deadline will have passed before the Transport Rule is 

finalized emphasizes the importance of obtaining reductions as 

expeditiously as practicable. In addition, reductions achieved in 

upwind states by the 2014 emissions year will help downwind states 

demonstrate attainment by the April 2015 deadline.

2006 PM2.5 NAAQS Attainment Deadlines. 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. Areas that fail to meet that deadline can 

request an extension to as late as December 2019.

Upwind emission reductions achieved by the 2014 emissions year 

will help meet the December 2014 attainment deadline. In addition, 

the first phase of reductions in 2012 will help many areas attain in 

a more expeditious manner.

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, if any, needed for compliance with the 2014 state 

emission budgets. (See further discussion in section V.C.2.)

 

PM2.5 NAAQS became effective on April 5, 2005. Designations for the 

2006 24-hour PM2.5 NAAQS became effective on December 14, 2009.
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1997 Ozone NAAQS Attainment Deadlines. 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 § 51.903. 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 

effectively corresponding to the end of the 2006, 2009, and 2012 

ozone seasons. The maximum attainment deadlines for the 1997 

standard run from the June 15, 2004 effective date of designation for 

that standard. The time periods are based on the time periods 

provided for these classifications in section 181 of the Act, 45 

U.S.C. § 7511(a). However, instead of running from the 1990 date of 

enactment of the CAA as specified in section 181, our regulation 

provides that they run from the date of designation. An area’s 

maximum attainment date is based on its nonattainment classification 

-- that is, whether it is classified as a marginal, moderate, 

serious, severe, or extreme ozone nonattainment area. Marginal areas 

have three years from designation to attain the standard. Moderate, 

serious, severe, and extreme areas have 6, 9, 15, and 20 years,

respectively. The maximum attainment deadlines associated with the 

1997 ozone standards are June 15, 2007 for marginal areas, June 15, 

2010 for moderate areas, and June 15, 2013 for serious areas. 

Because the actual deadline occurs in the middle of an ozone season, 

data from that ozone season is not considered when determining 
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whether the area has attained by the deadline. Thus, these maximum 

attainment deadline dates effectively correspond with the end of the 

2006, 2009, and 2012 ozone seasons. Reductions achieved or air 

quality improvements realized after those dates will not help the 

areas meet their maximum attainment deadlines.

Many areas have already attained the standard due in part to 

CAIR, federal mobile source standards, and other local, state, and 

federal measures. Other areas, however, have been reclassified to a 

higher classification either because they failed to attain by their 

attainment date or because the state requested reclassification to 

avoid missing an attainment date. Those that have not yet attained 

the standard now have maximum attainment dates ranging from June 2011 

(these are the moderate areas that have been granted a 1-year 

extension due to clean data for the 2009 ozone season) to June 2024. 

The areas classified as “serious” nonattainment areas have a June 

2013 maximum attainment deadline. Areas that missed their earlier 

deadlines and have been reclassified as “severe” or “extreme” 

nonattainment areas now have maximum nonattainment deadlines of June 

2019 and June 2024 respectively. As explained above, an area with a 

June 2013 deadline would need to attain based on ozone data from the 

2010-2012 ozone seasons, an area with a June 2019 deadline would need 

to attain based on ozone data from the 2016-2018 ozone seasons, and 

an area with a June 2024 deadline would need to attain based on ozone 

data from the 2021-2023 ozone seasons.
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The 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. If EPA 

determines that an area failed to attain by the 2013 deadline, the 

area would be reclassified to severe and would be subject to the more 

stringent emission control requirements that apply to the severe 

classification. The reductions will also help areas with later 

deadlines attain as expeditiously as practicable and improve air 

quality in those areas.

2012 Interim Compliance Deadline. EPA is requiring an initial 

phase of reductions starting in 2012. These reductions are necessary 

to ensure that significant contribution to nonattainment and 

interference with maintenance are eliminated as expeditiously as 

practicable and in time to help states meet their attainment 

deadlines. As the court emphasized in North Carolina, the 

significant contribution to nonattainment and interference with 

maintenance from upwind states must be eliminated as expeditiously as 

practicable to help downwind states to achieve attainment as 

expeditiously as practicable as required by the CAA. Further, 

reductions are needed by 2012 to help states attain before the June 

2013 maximum attainment date for “serious” ozone nonattainment areas, 

to ensure states attain as soon after the original April 2010 

attainment deadline for the 1997 PM2.5 NAAQS, and to help states attain 

before the December 2014 attainment deadline for the 2006 PM2.5 NAAQS.
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In addition, because this final rule will replace CAIR, EPA 

could not assume that after this rule is finalized, EGUs would 

continue to emit at the reduced emission levels achieved by CAIR. 

Instead, it is the emission reduction requirements in the proposed

FIPs that will determine the level of EGU emissions in the eastern 

United States. For this reason also, EPA concludes that it is 

appropriate to require an initial phase of reductions by 2012 to 

ensure that existing and planned SO2 and NOX controls operate as 

anticipated.

Addressing the Court’s Concern about Timing. As directed by the 

Court in North Carolina, 531 F.3d 896, and as described previously, 

EPA established the compliance deadlines in the Transport 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 necessary to ensure that states with June 2013 

maximum attainment deadlines get the assistance needed from upwind 

states to meet those deadlines. The 2012 deadline for compliance 

with the limits on annual NOX and annual SO2 emissions is necessary to 

ensure attainment as expeditiously as practicable in areas which 

failed to attain by the 2010 attainment deadline for the 1997 PM2.5

NAAQS and had to request an extension to 2015.

Similarly, the 2014 deadline for compliance with the limits on 

annual NOX and annual SO2 emissions is necessary to ensure that 

downwind states get the benefit of upwind reductions prior to the 
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December 2014 maximum attainment deadline for the 2006 PM2.5 NAAQS. 

It is also necessary to ensure reductions occur in time to assist 

with attainment in downwind 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).

The 2012 compliance deadline for the first-phase of annual 

NOX and annual SO2 emission reductions will assure the reductions are 

achieved as expeditiously as practicable. A significant amount of 

the emissions identified as significantly contributing to 

nonattainment or interfering with maintenance in other states can be 

eliminated by 2012. EPA believes it is appropriate to do so in light 

of the court’s direction to EPA to ensure states eliminate such 

emissions as expeditiously as practicable. North Carolina 531, F.3d 

at 930. 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 to 

nonattainment 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.
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b. Public comments and EPA responses.

EPA received numerous comments on the proposed compliance dates. 

A number of commenters supported EPA’s compliance schedule and 

rationale. Other commenters supported extending the compliance 

deadlines to later dates.

Many commenters questioned the technical feasibility of 

achieving the required reductions by the 2012 and 2014 dates. EPA’s 

responses to those comments are discussed below in section VII.C.2.

Other commenters provided policy and legal arguments for 

allowing states to develop SIP alternatives to the FIP, and to build 

time for that SIP development and review process into the compliance 

schedule. For example, some commenters asserted that the requirement 

in the CAA for providing reductions “as expeditiously as practicable” 

must be balanced with CAA provisions allowing states to develop state 

implementation plans prior to EPA imposing FIPs. EPA responses to 

those comments are discussed in section X. 

Some commenters suggested that EPA had the ability to leave CAIR 

in place for a transition period, and by doing this EPA could allow 

for a longer compliance period for this rule. EPA does not believe 

it would be appropriate, in light of the Court’s decision in North 

Carolina, to establish a lengthy transition period to the rule that 

will replace CAIR. Although the Court decided on rehearing to remand 

CAIR without vacatur, the Court stressed its prior decision that CAIR 

was deeply flawed and EPA’s obligation to remedy those flaws. North 

Carolina, 550 F.3d 1176. Although the Court did not set a definitive 
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deadline for corrective action, the Court took care to note that the 

effectiveness of its opinion would not be delayed “indefinitely” and 

that petitioners could bring a mandamus petition if EPA were to fail 

to modify CAIR in a manner consistent with its prior opinion. Id. 

Given the Court’s emphasis on remedying CAIR’s flaws expeditiously, 

EPA does not believe it would be appropriate to establish a lengthy 

transition period to the rule which is to replace CAIR.

As relates to PM2.5, EPA received a number of comments on its 

proposal to include a 2012 deadline to ensure that emission 

reductions needed to reduce PM2.5 be achieved “as expeditiously as 

practicable.” Some commenters supported EPA’s 2012 deadline. Other 

commenters believed that it was unnecessary and unwarranted for EPA 

to impose emission reduction requirements in advance of the 2014

attainment date. In light of the 2014 five-year attainment date for 

the 2006 PM2.5 NAAQS (with a possible extension to 2019), and the 

possible extension to April 2015 for the 1997 PM2.5 NAAQS, these 

commenters believed EPA’s 2012 emission reduction requirements for 

annual PM2.5 and NOX were not necessary. EPA disagrees with these 

commenters, for a number of reasons. First, EPA notes (supported by 

commenters) that there is a clear statutory obligation to attain “as 

expeditiously as practicable.” Second, EPA notes that there are 

feasible reductions available by 2012. Third, EPA believes that the 

substantial health and environmental benefits achieved by the rule 

underscore the importance of achieving the reductions as soon as 

possible.
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With respect to ozone, some commenters noted that the proposed 

rule required ozone reductions by 2012 for states impacting areas 

which EPA’s analysis shows will attain the 1997 ozone NAAQS by 2014 

without further controls. Those commenters questioned the importance 

of getting reductions in such states and whether the 2012 deadline is 

necessary. EPA disagrees with those comments. Except for Houston,

all ozone areas within the region addressed by this rule have 

attainment dates no later than 2013. In effect, this means that 

emission reductions needed to attain the 1997 ozone NAAQS must be in 

place by the 2012 ozone season. EPA believes that if there are 

reductions available by 2012, and those emission reductions have in 

fact been identified, it is appropriate and necessary to ensure that 

those reductions are in place.

2. Compliance and Deployment of Pollution Control Technologies

The power industry will undertake a diverse set of actions to 

comply with the Transport Rule at the start of 2012 and another set 

of actions when companies in Group 1 states comply with more 

stringent SO2 budgets at the start of 2014. In 2012, the industry 

will largely meet the rule’s NOX requirements by: operating an 

extensive existing set of combustion and post-combustion controls on 

fossil fuel-fired generators; dispatching lower emitting units more 

often; and installing and operating a limited amount of relatively 

simple NOX pollution controls in states not previously subject to 

CAIR. For the SO2 requirements, EPA anticipates at a minimum that 

coal-fired generators will operate the substantial capacity of 
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advanced pollution controls already in place or scheduled for 2012 

use; some units will also elect to burn lower-sulfur coals; and the 

fleet will increase dispatch from lower-sulfur-emitting units as well 

as from natural gas-fired generators. EPA provides a more detailed 

explanation below of how fuel switching to lower sulfur coals 

factored in to the design of the final Transport Rule.

By 2014, EPA’s budgets under the Transport Rule will sustain 

previous NOX and SO2 reductions as well as account for reductions from 

additional advanced NOX and SO2 controls that are driven by other 

state and federal requirements. In addition to these reductions, 

companies in Group 1 states are also projected to add a limited 

amount of advanced SO2 controls in 2014 that will be discussed below. 

EPA’s expectations are supported by the IPM analysis reported in 

this rule’s RIA (see Chapter 7). Notably, since EPA has established 

a cap and trade control system for lowering NOX and SO2 emissions, 

individual owners and operators of covered units have some 

flexibility in meeting the program’s requirements as needed and are 

free to find alternative ways to comply. The RIA clearly shows a 

viable known pathway for owners and operators to comply at reasonable 

costs, although it is not the only compliance pathway possible under 

this flexible regulation that could deliver the emission reductions 

required under the rule. Notably, by 2014 and beyond, the power 

industry may also augment the projected compliance efforts with 

programs aimed at improving energy efficiency.
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Table VII.C.2-1 shows EPA’s projection of the amount of existing 

coal-fired generating capacity in gigawatts (GW) that may retrofit 

various systems for compliance with this rule.

Table VII.C.2-1 Projected Potential Air Pollution Control (APC) 

Retrofits for Transport Rule59

Capacity 

retrofitted by:

Wet FGD Dry FGD DSI SCR LNB/OFA

Improvements

January 1, 2012 10 GW

January 1, 2014 5.7 GW 0.2 GW 3.0 GW 0 GW 

EPA received proposal comments expressing a concern about the 

feasibility of deploying retrofit air pollution control (APC)

technologies in the time frames available between the final date of 

this rule and the compliance dates. As discussed below, EPA believes 

that it is feasible for the electric power sector and its APC supply 

chain to either make most of the projected retrofits in time to meet 

the 2012 and 2014 compliance deadlines, or to comply by other means. 

a. 2012 Power Industry Compliance

EPA’s analysis of emission reductions available in 2012 assumes 

year-round operation of existing post-combustion pollution controls 

in states covered for PM2.5 and ozone-season operation of NOX postcombustion controls in states covered for ozone. EPA also modeled 

emission reductions available in 2012 at the $500/ton threshold for 

SO2, $500/ton for annual NOX, and $500/ton for ozone-season NOX. 

 

59 GW: gigawatts of capacity retrofitted; FGD: flue gas 

desulfurization (SO2 control); DSI: dry sorbent injection (SO2

control); SCR: selective catalytic reduction (NOX control); LNB/OFA: 

low-NOX burner and/or overfire air (NOX controls)
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For SO2, EPA believes that reductions associated with the 

following methods of control are available and will be used as 

compliance strategies to meet the 2012/2013 budgets: 1) operation of 

existing controls year-round in PM2.5 states, 2) operation of 

scrubbers that are currently scheduled to come online by 2012, 3) 

some sources switching to lower-sulfur coal (see section VII.C.2.c

that follows), and 4) changes in dispatch and generation shifting 

from higher emitting units to lower emitting units. EPA modeling and 

selection of a $500/ton cost threshold includes all existing and 

planned controls operating year round (items 1 and 2). It also 

reflects an amount of coal switching and generation shifting that can 

be achieved for $500/ton. This set of expected actions was confirmed 

in the detailed modeling of EPA’s final remedy in the RIA and can be 

reviewed there.

The power sector is already strongly positioned to achieve the 

Transport Rule state budgets presented in section VI.D through at 

least three distinct strategies. First, the sector will optimize its 

use of the large proportions of advanced pollution controls already 

present throughout the fleet. Second, the sector will take advantage 

of the substantial new pollution control technology that is already 

on the way for deployment by 2012. Third, the remainder of the fleet 

will flexibly adopt the most economic low-emitting fuel mix available 

at each unit to deliver cost-effective emission reductions 

complementing the reductions achieved from optimized use of the 

fleet’s pollution control technology. The state maps in Chapter 7 of 
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this rule’s Regulatory Impact Analysis demonstrate how these emission 

reduction strategies for 2012 will build off of the sector’s historic 

trend toward cleaner generation profiles. Also, the detailed unitlevel projection files from EPA’s IPM power sector modeling of the 

Transport Rule remedy (found in the docket for this rulemaking) show 

how EGUs adopt these strategies to not only reach the 2012 budgets, 

but in fact in many states overcomply with the budgets and build up a 

bank of allowances under the programs for future flexibility. 

The following paragraphs illustrate the degree to which the 

existing fleet is already prepared to adopt these emission reductions 

in 2012 in order to attain the required emission reductions for SO2, 

annual NOX, and ozone-season NOX under the Transport Rule. More 

specifically, the illustrative paragraphs demonstrate emission 

reduction pathways for coal capacity to optimize or increase 

operation of existing control technology, timely implement existing 

plans to bring additional control technology on line, and to costeffectively make use of lower-emitting fuel alternatives.

Of the 240 GW of coal capacity in the Transport Rule region 

covered for fine particles, approximately 110 GW -– more than 45 

percent -- had existing advanced pollution control for SO2 already in 

place in 2010, including scrubbers (FGD), dry sorbent injection 

(DSI), or circulating fluidized bed boilers. Of this controlled coal 

capacity, EPA expects a significant portion will improve emission 

rates through either increased use of control technology and/or 

additional fuel switching. EPA notes that an additional 39 GW of 
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advanced SO2 controls in the region are scheduled to come online over 

the 2010-2012 timeframe and will also assist in meeting 2012 emission 

reduction requirements. Thus, by 2012 more than half of affected 

coal capacity –- 152 GW -- will be operating with advanced SO2 control 

equipment. Additionally, EPA expects approximately 40 GW of 

uncontrolled coal capacity in the region to take advantage of the 

existing coal supply infrastructure, possibly switching coal use or 

coal blending behaviors to make cost-effective reductions in SO2

emission rates where economic to respond to the Transport Rule 2012 

emission reduction requirements. 

EPA notes that approximately 136 GW of the 240 GW -– more than 

56 percent -- of coal capacity in the Transport Rule region covered 

for fine particles had existing advanced pollution control for NOX

already in place in 2010, including selective catalytic reduction 

(SCR), selective non-catalytic reduction (SNCR), or circulating 

fluidized bed boilers. Of this capacity, EPA anticipates a 

significant portion will improve their NOX emission rate through 

increased operation of these existing controls. Additionally, EPA 

notes that an additional 21 GW of SCR and 4 GW of enhanced combustion 

controls (including low-NOX burners and overfire air) are scheduled to 

come online in the region during the 2010-2012 timeframe, bringing 

the total region’s coal capacity operating with NOX emission reduction 

technology to 158 GW (more than 65 percent of total coal capacity in 

the Transport Rule fine particle region). EPA also projects that 

approximately 13 GW of coal capacity will make some reduction in 
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their NOX emission rates by enhancing performance of existing 

combustion controls or SNCR, or by fuel switching.

In the Transport Rule states covered under the ozone-season 

program, approximately 145 GW of the 260 GW (more than 55 percent) of 

coal capacity had existing NOX control technology in place in 2010. 

EPA expects a significant portion of that capacity to achieve 

emission reductions during the 2012 ozone-season through improved 

operation of SCR. Additionally, in the Transport Rule ozone region 

there will be approximately 21 GW of additional advanced NOX control 

installations and 7 GW of additional combustion control improvements

or installations coming online during the 2010 to 2012 time frame. 

EPA projects that 17 GW of coal capacity in the Transport Rule ozone 

region will reduce NOX emission rates by enhancing performance of 

existing combustion controls or SNCR or by fuel switching.

For NOX, EPA has also concluded that it is appropriate to require 

reductions through a limited amount of combustion control 

improvements, and in some cases, retrofits such as low-NOX burners 

(LNB) and/or overfire air (OFA). EPA recognizes that the 6-month 

time frame between rule finalization and start of the first 

compliance period would not allow for the installation of a major 

post-combustion NOX control such as SCR. Assumed improvements and 

retrofits for the January 1, 2012 deadline for annual NOX reductions 

therefore only involve the much simpler LNB/OFA control modifications 

or installations. Alternatively, some plant owners might choose to 
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achieve NOX reductions in a similar time period through an even 

simpler retrofit - SNCR.60

Although the improvements, and in some cases, installation of 

combustion controls would be an economic means of achieving emission 

reductions, these specific controls are not required for compliance 

purposes under the final Transport Rule remedy. Individual sources 

may comply through other measures (such as purchasing additional 

allowances) in the event that it takes more than 6 months for 

installation of a given combustion control. The vast majority of 

covered sources already have combustion controls installed; 

therefore, the NOX reductions associated with these incremental 

control improvements and installations are small.

Based on the Transport Rule’s geography, EPA estimates that 

approximately 10 GW of coal-fired units may improve, and in some 

cases, install LNB/OFA specifically in reaction to the Transport Rule 

NOX caps. EPA reflects the effects of these installations in the 2012 

annual and ozone-season NOX budgets, which would yield reductions of 

approximately 28,000 tons of annual NOX and 14,000 tons of ozoneseason NOX. EPA assumes these controls are cost effective at $500/ton 

and that they should be incentivized through budgets given the 2013 

attainment deadline for ozone areas classified as “serious.” Once 

 

60 David L. Wojichowski, SNCR System – Design, Installation, and 

Operating Experiencehttp://www.netl.doe.gov/publications/

proceedings/02/scr-sncr/ wojichowski-1.pdf
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installed, LNB/OFA operates any time the boiler is fired and thus 

yields NOX reductions beyond the ozone season alone.

In the proposal’s LNB technical support document,

61 EPA observes 

that LNB and/or OFA installations, burner modifications, or other NOX

reduction controls would likely have to be installed during fall 2011 

or spring 2012 outages in order to achieve significant reductions for 

2012. While this 6-month schedule is aggressive, industry has shown 

that it can be met. For example, Limestone Electric Generating 

Station Unit 2, an 820 MW tangentially-fired lignite unit, was 

retrofitted with Foster Wheeler’s Tangential Low NOX (TLN3) system in 

less than six months, including engineering, fabrication, delivery 

and installation.62 Harlee Branch Unit 4, a 535 MW cell-fired unit, 

was retrofitted with Riley Power’s low-NOX Dual Air Zone CCV burners 

on a similar schedule.63 These are tangentially-fired and wall-fired 

units, respectively, representative of the unit types that might make

LNB/OFA improvements for compliance with this rule. Although such 6-

month schedules can be achieved on some units, under favorable 

circumstances, historical projects suggest a more typical schedule 

 

61 Technical Support Document (TSD) for the Transport Rule, Docket ID 

No. EPA-HQ-OAR-2009-0491, Installation Timing for Low NOX Burners 

(LNB)

62 R. Pearce, J. Grusha, Reliant Energy Tangential Low NOX System at 

Limestone Unit 2 Cuts Texas Lignite, PRB and Pet Coke NOX, 

http://www.fwc.com/publications/tech_papers/files/tp_firsys_01_02.pdf

63 B. Courtemanche, et al, Reducing NOX Emissions and Commissioning 

Time on Southern Company Coal Fired Boilers With Low NOX Burners and 

CFD Analysis, http://www.babcockpower.com/pdf/t-182.pdf
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would be 12 to 16 months for the contractor’s portion of the work.64 

A plant owner’s project planning and procurement work in advance of a 

contract award would typically involve several additional months. On 

the other hand, there are other approaches that can also be 

implemented in a short time frame to achieve significant NOX

reduction. As mentioned above, relatively simple SNCR systems can be 

installed quickly; and the re-tuning or upgrading of existing 

combustion control systems can often provide significant NOX

reductions and can be performed quickly.65

As stated above, EPA believes that LNB/OFA modifications or 

retrofits would be possible during the 6-month interim between rule 

signature and the start of the first compliance period, particularly 

for those “early movers” who have initiated LNB projects based on the 

proposed rule. However, as shown in Table VII.C.2-2, below, even if 

all LNB modifications or installations are delayed until the 

beginning of the 2012 ozone season, the reductions only represent 1 

percent of most covered states’ annual NOX budgets, and no more than 

11 percent of any affected state’s annual NOX budget. Under such a 

scenario, these delayed reductions would still be well within the 18 

percent variability limit applied to each state’s annual NOX budget. 

In light of this limited consequence and the supporting material 

 

64 M. O’Donnell, Babcock & Wilcox Company, (personal communication 

with EPA staff, February 22, 2011)

65 N.C Widmer, et al, Coal Power, October 8, 2009, 

http://www.coalpowermag.com/ops_and_maintenance/Zonal-CombustionTuning-Systems-Improve-Coal-Fired-Boiler-Performance_226.html
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above, EPA includes LNB-driven NOX reductions in both annual and 

ozone-season NOX budgets for 2012.

Table VII.C.2-2 Earliest Reductions Assumed from LNB Installations in 

the Transport Rule States Subject to the Annual NOX Program*

NOX Reductions 

from LNB 

Operation from 

January - April 

(tons)

Annual NOX State 

Budget (tons)

Percent of 

Budget Met by 

Earliest LNB 

Reductions

Georgia 646 62,010 1%

Iowa 567 38,335 1%

Kansas 2,131 30,714 7%

Minnesota 2,303 29,572 8%

Nebraska 3,008 26,440 11%

Region-wide Total 8,656 1,245,869 1%

*Based on EPA IPM Analysis of Final Transport Rule

b. 2014 Power Industry Compliance

EPA projects that compliance with 2014 requirements for NOX will 

result largely from operation of existing and future controls 

required by state and other federal requirements, as well as the 

appropriate dispatch of the electric generation fleet. EPA does not 

project additional NOX pollution control retrofits aside from about 10 

GWs of combustion control improvements or retrofits projected for the 

2012 compliance period. To comply with the rule’s SO2 requirements, 

EPA projects that the power industry will rely on existing controls, 

operate newly installed advanced controls necessary for other binding 

state and federal requirements, rely more on relatively lower sulfur 

coals, and dispatch lower-emitting generation units. In Group 1 
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states, industry is projected to increase switching to lower sulfur 

coals and install a limited amount of additional scrubbers and other 

advanced pollution control technology. EPA’s assessment of the 

industry’s ability to install SO2 pollution controls in 2014 and 

undertake the projected coal switching follows below.

EPA’s modeling of least-cost compliance with the state budgets 

under the Transport Rule projects approximately 5.9 GW of FGD systems 

and lesser amounts of other technologies will be retrofitted by 2014 

for compliance with the Transport Rule.66,67 EPA’s schedule 

assumptions for these larger more complex projects were developed in 

an earlier study and mentioned in the proposal: 27 months for 

retrofitted wet FGD and 21 months for SCR.68 Note that a dry FGD 

 

66 Nearly all of the 5.9 GW of FGD retrofits are comprised by some 12 

units at 7 plants (Beckjord, Muskingum River, Homer City, Rockport, 

Kammer, Danskammer, and Will County). 

67 As noted elsewhere in this preamble, the projected impacts of this 

final rule presented in the preamble do not reflect minor technical 

corrections to SO2 budgets in three states (KY, MI, and NY) and 

assumed preliminary variability limits that were smaller than the 

variability limits finalized in this rule. EPA conducted sensitivity 

analysis factoring in these corrections; the results of this analysis 

include a small increase of about 700 MW of additional wet FGD 

retrofit projected for 2014. This projected additional retrofitting 

capacity is already required to retrofit under a consent decree and 

should therefore have already conducted advanced retrofit planning. 

EPA therefore believes that this incremental projected retrofit 

behavior (factoring in the technical corrections made after the main 

impact analyses were conducted) is feasible by 2014 for the same 

reasons presented in this section regarding the projected retrofit 

behavior from the main analysis of the final rule. 

68 EPA, Engineering and Economic Factors Affecting the Installation of 

Control Technologies for Multipollutant Strategies; EPA-600/R-02/073 

October 2002.
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system, due to its relatively simpler configuration and lesser cost, 

would typically take somewhat less time to retrofit than wet FGD.

As discussed below, EPA believes that its schedule assumptions 

remain reasonable expectations for sources that have completed most 

of their preliminary project planning and can quickly make 

commitments to proceed. These schedules do not include the extensive 

time that some plant owners might spend in making a decision on 

whether or not to retrofit. They do include the time needed to make

a final confirmation of the type of technology to be used at a 

particular site, to prepare bid requests, award contracts, perform 

engineering, obtain construction and operating permits (in parallel 

with project activities), perform construction, tie-in to the 

existing plant systems, and perform integrated systems testing. 

EPA received comments on the proposed rule indicating that some 

past single-unit APC retrofits had considerably longer schedules, 

with a few exceeding 48 months. EPA engineering staff have extensive 

experience with power plant and APC system design, construction, and 

operation. Based on that experience, EPA can observe that in the 

absence of a compelling deadline or major economic incentive, many 

large project schedules are considerably longer than necessary. 

Given further observations as explained below, EPA believes it is 

reasonable to expect that almost all future APC retrofits can be 

completed far more quickly than they were in recent history. 

EPA’s perspective on this matter derives in part from a comparison of 

longer APC schedules (as provided by some commenters) to the project 
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schedule for an entire new coal-fired unit, including its APC 

systems. Springerville Unit 3, for example, is a new 400 MW 

subbituminous coal-fired unit with SCR and dry FGD that became 

operational in July 2006, some 33 months after the turnkey 

engineering-construction contractor was given a notice to proceed 

with engineering.69 Springerville was clearly on an accelerated 

schedule, as its original planned schedule was about 38 months. 

Another example is Dallman Unit 4, a high-sulfur bituminous coalfired 200 MW unit with SCR, fabric filter, wet FGD, and wet ESP. 

Dallman Unit 4 was first synchronized in May 2009, several months 

ahead of schedule, and about 36 months after its turnkey contractor 

placed initial major equipment orders.70 The main point here is that 

recent APC project schedules, and those of large complex power 

projects, can be significantly accelerated. Because the scope and 

complexity of the work involved for an entire new coal unit and its 

APC systems is perhaps five times greater than that of a retrofit wet 

FGD system alone, EPA believes it is reasonable to expect that even 

the most complex retrofit APC project can be significantly 

accelerated as well. Additional factors are discussed below that 

 

69 Best Coal-fired Projects, Springerville Unit 3 Expansion Project, 

Power Engineering, November 2006, 

http://www.powergenworldwide.com/index/display/articledisplay/282547/

articles/power-engineering/volume-111/issue-1/features/projects-ofthe-year.html

70

http://www.cwlp.com/electric_division/generation/Dallman%204%20Power%

20Plant%20of%20the%20Year.pdf
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further support the feasibility of installing by 2014 the 5.9 GW of 

FGD retrofits projected for this rule. 

Although IPM modeling provides reliable estimates on a regional 

basis, and cannot be as accurate at the level of individual plants or 

units, it is informative and relevant to consider IPM’s plant level 

projections in this case. Although the IPM-projected retrofits named 

below may not actually occur, IPM projects that they would be 

economic and would allow industry to meet the tighter SO2 emission 

standards in Group 1 states in 2014. EPA notes that the owners of 

the particular plants mentioned below (Duke Energy, AEP, Edison 

International) are large, experienced, versatile utilities that have 

done considerable advance planning and should also have above-average 

flexibility to comply with state budgets across their fleets. EPA 

would expect such owners to have relatively little difficulty in 

permitting and financing FGD retrofits.

Of the Transport Rule-related FGD retrofits, 0.2 GW is projected 

to use dry FGD, which EPA expects to be simpler and quicker to 

install than wet FGD. Half of the 5.9 GW (Muskingum, Rockport) has 

already been committed under consent decrees to add controls or 

retire;71 and EPA reasonably believes that significant preliminary 

project planning work has already been done for those projects. An 

additional 1,200 MW (Homer City) had completed project planning and 

 

71http://www.epa.gov/compliance/resources/decrees/civil/caa/americanel

ectricpower-cd.pdf
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was ready to proceed in 2007, before putting the project on hold.72

The latter plant is now facing EPA legal action and the possibility 

of a required expeditious FGD retrofit.73 Thus, of the 5.9 GW of 

projected FGD retrofits resulting from this rule, nearly 75 percent 

appears to be in good position for an early start of construction, 

and over 3 GW of that would be bringing forward already committed 

compliance start dates. 

Any of the above mentioned potential retrofits or any other unit 

that might choose to retrofit FGD for a January 2014 compliance date 

will likely have to use various methods to accelerate the project 

schedule. Such methods could include the use of parallel permitting, 

overtime and/or two-shift work schedules during construction, and 5-

or 6-day work weeks instead of the 4-day x 10-hour schedules often 

used to minimize cost when time is not of the essence. Increased use 

of offsite modularization and pre-fabrication of APC components could 

also shorten schedules and reduce job hours. 

EPA believes that the January 1, 2014 compliance date is as 

expeditious as practicable for the sources installing large, complex 

control systems. The following additional observations support EPA’s 

expectation that the limited 5.9 GW of FGD retrofits can be realized 

in the 30 month interim between rule signature and the start of 2014:

 

72http://www.businesswire.com/news/home/20060731005193/en/ContractorsSelected-Install-Emissions-Control-System-Pennsylvania

73http://www.epa.gov/Compliance/resources/complaints/civil/caa/homerci

ty-cp.pdf
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● There are documented instances of large, complex wet FGD 

retrofits being deployed in less than 30-months (excluding the time 

for owners’ project planning). Examples are Killen Station Unit 274, 

and Asheville Unit 1.

75

● In 2009 the APC supply chain deployed more than six times 

more GW capacity of FGD and SCR controls than the 5.9 GW of FGD that 

would be deployed by 2014 under this Rule.

● The APC supply chain has seen a 2-year decline in 

deployments since its peak in 2009, but in 2011 is nonetheless 

putting into service about three times more GW capacity of FGD and 

SCR controls than the 5.9 of FGD that would be deployed under this 

Rule.

● Because the supply chain has been in decline, but remains 

quite active, there are now adequate supply chain resources available 

that can be quickly reengaged to support a rapid deployment of 5.9 GW 

of FGD.

EPA recognizes that the installation of any amount of scrubbers 

in this short time frame will require aggressive action by plant 

owners and that the owners who can meet this schedule will already 

 

74 Black & Veatch, 

http://www.bv.com/News_3_Publications/News_Releases/2005/0503.aspx 

(start), http://www.bv.com/wcm/press_release/07252007_9767.aspx

(completion)

75 PowerGenWorldwide, Projects of the Year, January 1, 2007, 

http://www.powergenworldwide.com/index/display/articledisplay/282547/

articles/power-engineering/volume-111/issue-1/features/projects-ofthe-year.html
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have done their project planning and will be ready to place orders. 

An example of such “early movers” was seen in the power sector’s 

anticipation of CAIR. EPA data indicate that solely CAIR-driven FGD 

and SCR deployments of about 6 GW occurred within two and one-half 

years after CAIR’s finalization in mid-2005, showing that at least 20 

percent of the total CAIR-only controls effort through a 2010 

compliance date was sufficiently planned for installation to start 

before or immediately upon finalization of the rule. EPA reasonably 

expects that similar advance planning has already been done for units 

that would retrofit under this rule. 

In the event that a particular control installation requires 

additional time into 2014 to come online, EPA believes compliance 

would not be jeopardized given the ability of sources to purchase 

allowances during that time. This approach could be supported by 

some sources with FGD that have the ability to increase their SO2

removal above historic rates, perhaps through relatively low cost 

upgrades to improve scrubber effectiveness, or by operating scrubbers 

at higher chemistry ratios. The ability of sources to temporarily or 

permanently substitute dry DSI for FGD serves as another backstop for 

any feasibility issues regarding FGD. Note that the updated modeling 

for this rule projects the addition by 2014 of about 3 GW of DSI for 

SO2 control using trona or other sorbent. DSI is a relatively low 
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capital cost technology that readily can be installed in the time 

frame available for compliance.76,77 

It should also be noted that most APC retrofits will involve a 

source outage for final “tie-in” of retrofitted systems to existing 

systems, during which time emissions from the affected units are 

zero. For some sources, the duration of this tie-in outage may 

effectively extend the deadline by which all of the projected 

emission reductions need to occur. 

Although EPA believes that installation of 5.9 GW of FGD at

facilities by January 1, 2014 is feasible, EPA also conducted an IPM

sensitivity analysis to examine a scenario in which FGD retrofitting 

by 2014 is not allowed. Results of EPA’s “no FGD build in 2014” 

analysis indicate that if the power industry were subjected to the 

requirements of this rule without an FGD retrofit option for 

compliance until after 2014, covered units would still be able to 

meet the Transport Rule requirements in every state while respecting 

each state’s assurance level. (See the docket to this rulemaking for 

the IPM run titled "TR_No_FGD_ in2014_Scenario_Final.”)

In this scenario without the availability of new FGD by 2014,

sources in covered states complied with the Transport Rule budgets by 

using moderate additional amounts of DSI retrofits, switching to 

 

76 ICAC letter to Senator Carper, November 3, 2010, 

http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf

77 Assessment of Technology Options Available to Achieve Reductions of 

Hazardous Air Pollutants, URS Corporation, April 5, 2011, 

http://www.supportcleanair.com/resources/studies/file/4-8-11-

URSTechnologyReport.pdf
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larger shares of sub-bituminous coal, and dispatching larger amounts 

of natural gas-fired generation in lieu of the FGD retrofits that are 

projected as being most economic under modeling of the Transport Rule 

remedy. Because new FGD capacity is included in EPA’s projection of

the least-cost set of SO2 emission reductions required in Group 1 

states, the “no FGD” sensitivity scenario did project higher system 

costs, although these costs were still substantially lower than the 

remedy EPA modeled in the Transport Rule proposal.

The “no FGD” analysis indicates that while the ability of Group 

1 states to meet their 2014 SO2 budgets is facilitated by FGD 

retrofits, they are by no means required, nor is Transport Rule 

compliance jeopardized by their absence. Even under a scenario in 

which sources fail to complete FGD retrofits by 2014, sources in the 

affected states would have other compliance options available at

reasonable cost to meet the state’s budget requirements. This 

analysis shows that Group 1 states would be able to comply with their 

2014 SO2 budgets by relying on other emission reduction opportunities

that do not require FGD retrofits. EPA analysis confirms that those 

alternatives are feasible both in terms of cost and timing.

Finally, EPA recognizes that, when finalized later this year as 

currently scheduled, the Mercury and Air Toxics Standards (MATS) will 

require significant retrofit activity at covered sources in the power 

sector with a 2015 compliance date for that rule. EPA's projections 

of retrofit activity under the final Transport Rule are highly 

compatible with its projections of retrofit activity under the 
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proposed MATS (which included the proposed Transport Rule in its 

baseline). EPA therefore anticipates that the Transport Rule's 

projected retrofit activity will not only be the least-cost 

compliance pathway to meeting state budgets in 2014 but will also 

accelerate emission reductions subsequently required by the effective 

date of MATS. The final Transport Rule's projected 2014 retrofit 

installations will also further incentivize the power sector to ramp 

up its retrofit installation capabilities to achieve broader 

deployment of the projected pollution control retrofits under the 

proposed MATS.

Considering all the reasons given above, EPA has concluded that 

the 2014 requirements for SO2 emissions in the states covered by the 

Transport Rule are reasonable and can be met by the power industry by 

a variety of means.

c. Coal Switching for SO2 Compliance in 2012 and 2014

Coal switching is another mechanism which can be used along with 

operating pollution controls in 2012 for compliance. It will be a 

complementary activity by many coal-fired units alongside of 

operating pollution controls and the addition of more scrubbers and 

DSI in 2014.

In the proposal, EPA noted that coal switching could serve as a 

compliance mechanism for 2012. EPA requested comment on the 

reasonableness of EPA’s assumption that coal switching will have 

relatively little cost or schedule impact on most units. EPA 

received substantial comment suggesting that the coal switching and 
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coal blending projected by EPA modeling are not feasible for all 

units, and that, if feasible, would often incur a cost through the 

derating of the unit associated with the switch to a lower sulfur 

coal or coal blend. Additionally, sources indicated that coal 

switching by 2012 would not always be possible in the six month 

window between final rule signature and start of compliance. These 

feasibility concerns stemmed from restrictions included in existing 

coal supply contracts and from boiler design constraints that may 

hinder coal switching within a 6 month window. 

EPA agrees with these concerns and revised its IPM modeling to 

limit coal switching capability in 2012 for particular units that may 

have trouble switching coals or coal blends in a six month time 

frame. A cost adder was also included in the IPM modeling for coal 

switching to capture the potential cost burden of deratings that 

might accompany switching to a very low sulfur subbituminous coal or 

coal blend.

A particular commenter concern regarding switching to lower 

sulfur within the eastern bituminous coals related to a possible 

impact on the performance of 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 
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factors. In any case, industry experience indicates that relatively 

inexpensive practices to maintain high ESP performance on lower 

sulfur bituminous coals are available and can be used successfully 

where necessary. These include a range of upgrades to ESP components 

and flue gas conditioning.78 EPA therefore assumes that it will not 

be necessary for units that switch from higher to lower sulfur 

bituminous to make a costly replacement of the ESP. 

Coal switching as a SO2 compliance option might also include 

switching from bituminous to subbituminous coal. EPA’s analysis does 

not assume that a unit designed for bituminous can switch to (very 

low sulfur) subbituminous coal unless the unit’s historical data 

demonstrate that capability in the past. EPA assumes that units with 

that demonstrated capability have already made any investments needed 

to handle a switch back to the use of subbituminous coal at a similar 

percentage of its heat input as in the past. For IPM analysis in the 

final rule EPA also introduced a coal switching option that assumes 

that units can increase a historically low percentage use of 

subbituminous to a “maximum” level, if economic. This option 

includes an appropriate derate in output, increase in heat rate, and 

additional capital and operating costs. Details of this and other 

IPM updates for this rule are provided in the IPM Modeling 

Documentation in the docket for this rulemaking (“Documentation 

 

78 Assessment of Technology Options Available to Achieve Reductions of 

Hazardous Air Pollutants, URS Corporation, April 5, 2011,

http://www.supportcleanair.com/resources/studies/file/4-8-11-

URSTechnologyReport.pdf
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Supplement for EPA Base Case v.4.10_FTransport – Updates for Final 

Transport Rule”).

Some commenters also expressed concern with the assumption that coalswitching from lignite to subbituminous is a cost-effective or 

feasible emission reduction strategy, particularly at Texas EGUs. 

EPA carefully considered these comments and adjusted its modeling of 

cost-effective reductions to address this concern. Specifically, EPA 

made adjustment in the model so that it assumes coal-switching is not 

a compliance option at the specific units where commenters identified 

technical barriers to subbituminous coal consumption. The Transport 

Rule emission budgets are based on this adjusted modeling which does 

not assume any infeasible coal-switching from lignite to 

subbituminous. In addition, EPA’s analysis of cost-effective 

reductions in each state presented in section VI.B shows that Texas 

is capable of cost-effectively meeting its Transport Rule emission 

budgets; however, EPA also conducted sensitivity analysis that shows 

Texas can also achieve the required cost-effective emission 

reductions even while maintaining current levels of lignite 

consumption at affected EGUs. More details regarding this analysis, 

including a table comparing key parameters between the main Transport 

Rule remedy analysis and this Texas lignite sensitivity, can be found 

in the response to comments document and the IPM model output files 

included in the docket for this rulemaking.

D. Allocation of Emission Allowances
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Under the final rule, EPA distributes a number of SO2, annual 

NOX, and ozone-season NOX emission allowances to covered units in each 

state equal to the SO2, annual NOX, and ozone-season NOX budgets for 

those states. These budgets are addressed in section VI.D of this 

preamble. This section discusses the methodology EPA uses to 

allocate allowances to covered units in each state.

As discussed later in section VII.D.2, EPA is setting aside a 

base 2 percent of each state’s budgets for allowance allocations for 

new units, with 5 percent of that 2 percent, or 0.1 percent of the 

total state budget being set aside for new units located in Indian 

country. To this base 2 percent, EPA is setting aside an additional 

percentage on a state-by-state basis, ranging from 0 to 6 percent 

(yielding total set asides of 2 percent to 8 percent), for units 

planned to be built. The remainder of the state budget is allocated 

to existing units. Tables VI.D.-3 and VI.D.-4 in this preamble show 

the SO2, annual NOX, and ozone-season NOX budgets for each covered 

state (without the variability limits). In allocating allowances to 

existing and new units, EPA distributes four discrete types of 

emission allowances for four separate programs: SO2 Group 1 

allowances, SO2 Group 2 allowances, annual NOX allowances, and ozoneseason NOX allowances.

In the SO2 Group 1 and SO2 Group 2 programs, each SO2 allowance 

authorizes the emission of one ton of SO2 in that vintage year or 

earlier and is usable for compliance only in the program for which 

the allowance was issued. In the annual NOX program, each annual NOX
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allowance authorizes the emission of one ton of NOX in that vintage 

year or earlier in that program. In the ozone-season NOX program, 

each ozone-season NOX allowance authorizes the emission of one ton of 

NOX during the regulatory ozone season (May through September for this 

final rule) in that vintage year or earlier for that program. 

In each of the four trading programs, a covered source is 

required to hold sufficient allowances (issued in the respective 

trading program) to cover the emissions from all covered units at the 

source during the control period. EPA assesses compliance with these 

allowance-holding requirements at the source (i.e., facility) level.

This section explains how, in this final rule, EPA allocates a 

state’s budget to existing units and new units in that state. This 

section also describes the new unit set-asides and Indian country new 

unit set-asides in each state, allocations to units that are not 

operating, and the recordation of allowance allocations in source 

compliance accounts.

1. Allocations to Existing Units 

This subsection describes the methodology EPA will use in the 

FIPs finalized in this action to allocate to existing units.79 The 

same methodology will be used to allocate allowances to existing 

units for all four trading programs. 

 

79 In this rule, existing units are defined as covered units that 

commenced commercial operation prior to January 1, 2010. As 

explained in greater detail in Section VII.B. of this preamble, EPA 

decided to use this definition to ensure that EPA would have at least 

1 full year of quality-assured data on which to base a unit’s 

allocation.
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For the reasons explained below, EPA has decided to base 

allocations made under the FIPs on historic heat input, subject to a 

maximum allocation limit to any individual unit based on that unit’s 

maximum historic emissions. This methodology gives each existing 

unit an allocation equal to its share of the state’s historic heat 

input for all the covered units in the program, except where that 

allocation would exceed its maximum historic emissions; this 

methodology constrains the heat input-based allocations from 

exceeding any unit’s maximum historic emissions. Further detail on 

the implementation of this approach is provided in section VII.D.1.c 

below as well as in the Allowance Allocation Final Rule TSD in the 

docket for this rulemaking. All existing-unit allocations for 2012 

will be made pursuant to the FIPs. However, as described in section 

X, states may submit SIPs or abbreviated SIPs to use different 

allocation methodologies for allowances of vintage year 2013 and 

later. 

a. Summary of allocation methodologies and comments

EPA took comment on three distinct allocation methodologies for 

existing units. The first –- an emissions-based option -– was 

presented in the original Transport Rule proposal (75 FR 45309). The 

second and third -– heat input option 1 and heat input option 2 -–

were presented in a Notice of Data Availability (76 FR 1113). EPA 

received numerous comments on all three options. 

i. Emission-based allocation methodology 
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The emission-based option presented in the original Transport 

Rule proposal would base allowance allocations to existing units on 

each covered unit’s calculated emission “share” of that state’s 

budget for a given pollutant under the Transport Rule. The proposed 

rule stated 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...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” (75 FR 45309).

Many commenters objected to this projected emission allocation 

methodology. Commenters offered two principle objections. First, 

they argued EPA should not use unit-level model projections to 

allocate allowances. Second, they argued the use of any emissionbased allowance methodology is improper. Many of these commenters 

argued that instead of an emission-based allocation methodology, EPA 

should use a heat-input-based allocation methodology. 

Commenters’ objections to the use of unit level model 

projections focused primarily on the accuracy of such projections. 

While many commenters supported the use of modeling projections in 

determining state emission budgets, they argued that the unit-level 

model projections were not sufficiently accurate to use as a basis 
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for allocating allowances to individual units. Among other things, 

they argued that the modeling used for the proposal did not recognize 

certain non-economic factors that may cause individual units to 

operate differently than the model projects. Commenters also argued 

that EPA’s modeling does not capture all up-to-date contracts and 

other economic arrangements made at the unit-level which may affect 

operational decision-making. Some of these commenters continued to 

support the use of an emission-based allocation approach, but urged 

EPA to use more up-to-date and specific unit-level data in its 

modeling projections. Others opposed the use of any emission-based 

allocation approach.

EPA acknowledges that the model may not, at this time, capture 

all relevant operational decision factors for each individual unit. 

EPA also recognizes that there are unit-level details of operational 

decision-making and economic arrangements (such as certain contracts 

for electricity sales) that are private and thus unavailable to EPA

on an ongoing basis for modeling purposes. EPA believes these 

potential omissions would not have a significant impact on EPA’s 

determination of significant contribution at the state level; 

however, EPA recognizes they could conceivably have a significant

impact on projections at the individual unit level. EPA thus agrees 

with commenters that the unit-level emission projections from its 

modeling may not reflect all possible operational decisions at a 

given unit and are therefore not an appropriate proxy measure to use 

as a basis for allocating allowances to individual units. 
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Many commenters also argued that, even if the emission 

projections could be adjusted to capture all known and up-to-date 

unit-level operational factors, EPA should not use any emission-based 

allocation approach. They argued that an emission-based approach 

should not be used because it is not fuel-neutral. That is to say, 

the type of fuel consumed significantly affects the emissions from, 

and therefore the allocation to, a given unit under an emission-based 

approach. Commenters argued that an approach that is not fuelneutral effectively awards higher-emitting units. Commenters also 

argued that a projected emission-based approach should not be used 

because it is not control-neutral. In other words, whether or not a 

unit has installed controls would significantly affect the allocation 

for a given unit under an emission-based approach. Under an 

emission-based approach, controlled units receive significantly fewer 

allowances than uncontrolled units. Such an approach, commenters 

pointed out, effectively penalizes sources who have taken action to 

reduce emissions. 

EPA acknowledges that an emission-based approach would not be 

fuel-neutral or control-neutral. EPA notes that the D.C. Circuit 

rejected the fuel adjustment factors that were used in CAIR to adjust 

state budgets based on the type of fuel burned at each covered unit. 

North Carolina, 531 F.3d 918-21 (rejecting use of fuel adjustments in 

setting state NOX budgets). While the proposal’s allocation 

methodology did not explicitly adopt “fuel adjustment factors” for 

allocation purposes, EPA recognizes that an emission-based allocation 
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methodology effectively advantages or disadvantages units based on 

the type of fuel they combust.

In addition, several commenters argued that the proposal’s 

emission-based methodology would inappropriately reward the highest 

emitters under the program with more allowances than their loweremitting counterparts would receive. EPA acknowledges that such a 

methodology would allocate more allowances to units whose emissions 

make up a larger share of the proposed Transport Rule programs’ state 

budgets. EPA notes that because any allocation patterns under the 

Transport Rule FIPs would be established in advance of covered 

sources’ compliance decisions (i.e., decisions regarding how much to 

emit under the programs), covered sources cannot be “rewarded” by 

adjusting their future emissions. However, EPA notes commenters’ 

observations that the proposal’s methodology would reduce allocations 

to units that previously installed pollution control technology or 

invested in cleaner forms of generation in anticipation of CAIR. EPA 

concluded in review of these comments that the proposed Transport 

Rule’s allocation methodology unintentionally yielded this 

distributional outcome. EPA therefore considered alternative 

allocation methodologies described below. 

A substantial portion of the commenters who objected to the 

proposal’s emission-based allocation option urged EPA to consider 

historic heat input based approaches. EPA agreed it should accept 

comment on the use of historic heat input-based approaches and 

published a NODA to provide an opportunity for comment on two 
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specific heat input options and the allocations that would result 

from application of those options to the proposed Transport Rule 

state budgets.

ii. Heat input allocation option 1

The first heat input option presented by EPA in the NODA 

(“Option 1”) allocates allowances to units based solely on their 

historic heat input. Under this option, EPA would establish a 5-year 

historic heat input baseline for each covered unit and allocate 

allowances to sources at levels proportional to the each unit’s share 

of the total historic heat input at all covered units in that state. 

Numerous commenters supported the use of a heat-input based 

allocation methodology. These commenters stated that basing 

allocations on historic heat input has the following advantages over 

the proposal’s emission-based allocation methodology:

(A) For certain types of units, historic heat input data may 

offer a better representation of unit-level operation than model 

projections of unit-level emissions; furthermore, for all units, 

historic heat input is typically represented by quality-assured data 

reported by sources from continuous emission monitoring systems, 

which strengthens its accuracy.

(B) Historic heat input data are generally fuel-neutral in that 

they do not generally yield higher allocations for units burning or 

projected to burn higher emitting fuels.

(C) Historic heat input data are generally emission-controlneutral in that they do not generally yield reduced allocations for 
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units that installed or are projected to install pollution control 

technology.

Many commenters also argued that a heat input-based allocation 

methodology should be used because, unlike the proposal’s emissionbased methodology, a heat-input based methodology would be generally 

fuel-neutral and control–neutral and would rely on unit-level 

quality-assured data instead of on modeling projections.

Several commenters expressed support for specific aspects of 

heat input option number one. From a technical standpoint, 

commenters noted that heat input option 1 relied on the highestquality and most transparent data EPA had provided as a basis for 

allocating allowances under the Transport Rule programs. They argued 

that the calculation methodology for heat input option 1 is more 

readily re-created and understood by sources than either the 

proposal’s methodology or EPA’s application of the “reasonable upperbound capacity utilization factor and a well-controlled emission 

rate” in heat input option 2 (described in greater detail below). 

They also pointed out that it is similar to methodologies used in 

previous trading programs, such as the NOX Budget Trading Program (see

40 CFR 96.42(a) & (b) (calculating each existing EGU’s allocation by 

multiplying each unit’s historic heat input by 0.15 lb/mmBtu)). In 

addition, commenters supported the reliance of heat input option 1 on 

continuous emission monitoring system (CEMS) data that are reported 

to EPA and certified by the source’s designated representative (DR) 

as accurate and complete. In addition, many commenters supported 
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EPA’s use of historic data without further transformation by any 

calculation factors created by EPA. 

From a policy perspective, commenters highlighted the fuel 

neutrality and emission-control neutrality aspects of heat input 

option 1. They noted that this option does not, in contrast to the 

proposal’s emission-based methodology, penalize a source, through a 

reduced allowance allocation, for having chosen a generation 

technology or emission control technology that was more favorable to 

public health and the environment. EPA agrees with these 

observations. The allocation pattern associated with this option 

does not advantage or disadvantage units based on either the fuel 

consumed or the presence or absence of a pollution control 

technology. In this respect, it is a neutral approach that does not 

“reward” high-emitting units or “penalize” low-emitting units, 

including, for example, those units on which pollution control 

technology was installed in anticipation of CAIR.

EPA agrees with the aforementioned arguments from these 

commenters regarding the technical and policy merits of this heat 

input-based allocation methodology. EPA believes that the qualityassured heat input data reported by EGUs under its programs are among 

the most detailed and sound unit-level data accessible by EPA. EPA 

believes the calculation of any individual unit’s share of this 

historic heat input data is a straightforward, clear, and simple 

calculation to perform, such that EPA’s calculated allowance 

allocations under this approach can be relatively easily replicated.
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EPA also agrees with commenters that such data has previously 

supported allowance allocation procedures for highly successful 

program implementation of the ARP and the NOX Budget Trading Program 

(NBP). Notably, Congress chose a heat input-based allocation 

approach when authorizing the ARP in title IV of the Clean Air Act, 

suggesting that Congress viewed heat input as a reasonable basis for 

allocation. Additionally, EPA’s selection of a heat input-based 

approach for the NBP was not legally challenged, implying that 

stakeholders generally saw a heat input-based approach as reasonable.

EPA also agrees with comments observing that allocations made 

under this heat input approach do not advantage or disadvantage units 

based on their choice of fuel combustion or pollution control 

technology, and that allocations under this approach would thus be 

“fuel-neutral” and “control-neutral.” EPA also agrees with 

commenters that unlike the proposed rule’s emission-based 

methodology, this heat input methodology does not yield lower 

allocation to units that reduced emissions in advance of the 

Transport Rule relative to units that did not make such emission 

reductions.

Other commenters objected to the use of a heat-input based 

allocation methodology. These commenters argued that the allocation 

pattern associated with a heat-input allocation methodology would 

yield “windfall profits” -- in the form of allowance allocations 

greatly in excess of likely emissions -- for certain units, 

particularly with regard to SO2 allowance allocations for units 
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combusting natural gas. EPA disagrees with the characterization of 

the excess allowances as “windfall profits.” Allocations based on 

heat-input alone are fuel-neutral and control-neutral. The 

characterization of the heat-input allocation methodology as creating 

“windfall profits” for any unit is based on the assumption that all 

units should be allocated allowances based on emissions, not heat 

input. In arguing the heat-input approach creates a “windfall” for 

some units, commenters are assuming that the allocation of allowances 

above a unit’s projected emissions constitutes a “windfall” –- a 

conclusion EPA does not accept. EPA believes that under market-based 

regulatory programs, it is appropriate to base initial allowance 

allocations on a neutral factor and allow the market to determine the 

least-cost pattern of emission reductions in each state to achieve 

the reductions that address the state’s significant contribution and 

interference with maintenance under the final Transport Rule 

programs. EPA disagrees that future allowance transactions 

(following a neutral-factor initial allocation) in response to these 

market forces can be characterized as “windfall profits.” As 

explained above, EPA believes it is appropriate to allocate 

allowances based on a neutral factor. Commenters appear to ask EPA, 

instead of allocating based on a neutral factor, to consider the 

unit-level distributional impacts of each allocation methodology and 

to select an allocation methodology on the basis of equity. EPA does 

not believe it would be appropriate for the agency to pick an 

allocation methodology to achieve any particular distributional 
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outcome as such considerations are not related to the statutory 

mandate of CAA section 110(a)(2)(D)(i)(I). Instead, EPA believes it 

is appropriate to allocate allowances to sources covered by its 

trading programs based on a neutral factor. Furthermore, CAA section 

110(a)(2)(D)(i)(I) requires prohibition of certain emissions within a 

state (i.e., a state’s significant contribution and interference 

with maintenance). It does not direct EPA to use any particular 

methodology for allocating allowances under a trading program 

designed to ensure all such emissions are prohibited. As such, EPA 

believes it is appropriate to allocate allowances based on a neutral 

factor representing fossil energy content used to produce 

electricity. Detailed considerations of equity, as the D.C. Circuit 

reminded EPA, are not related to the statutory mandate of section 

110(a)(2)(D)(i)(I). North Carolina, 531 F.3d 921.

Some commenters objected to the use of a heat input-based 

approach by arguing that higher-emitting units would not receive an

initial allocation sufficient to cover their emissions. EPA does not 

believe it is reasonable to expect initial allocations to cover each

unit’s emissions under a trading program aimed at producing 

meaningful emission reductions. In its administration of prior 

trading programs such as the ARP and the NBP, EPA has made initial 

allowance allocations using a heat input-based approach, and 

virtually all covered sources have successfully complied at the end 

of each compliance period by making cost-effective emission 

reductions, purchasing additional allowances through robust markets 
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to cover emissions, or undertaking both types of activities. EPA 

disagrees with commenters’ arguments that allowance allocations 

should be used to compensate units with higher emissions.

iii. Heat input allocation methodology option 2

The second heat input option presented by EPA for public comment 

also would use historic heat input but would apply a constraint to 

unit-level allocations under certain circumstances. Specifically, 

under this option unit-level allocations would not be allowed to 

exceed what EPA determines, based on historic emissions and other 

factors, to be the units’ “reasonably foreseeable maximum emissions.”

To apply this constraint, EPA first would determine whether the 

allocation to a unit under an unconstrained heat-input methodology 

would exceed that unit’s maximum historic emissions of the relevant 

pollutant since 2003 “in order to reflect unit-level emissions before 

and after the promulgation of the CAIR” (76 FR 1115). Using this 

baseline would enhance the neutrality of the maximum historic 

emissions data because it would capture the highest emissions of the 

unit during that period regardless of what fuels it combusted or what 

pollution control devices were installed and used at any particular 

time during that period. In other words, a unit’s allocation would 

not be reduced due to a recent decision to switch fuels or install 

pollution controls.

Second, for this option, EPA then would adjust that maximum 

historic emissions data by applying a “well-controlled rate maximum,” 

designed to place “a reasonably foreseeable maximum emissions level 
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reflecting a reasonable upper-bound capacity utilization factor and a 

well-controlled emission rate that all units (regardless of the type 

of fuel they combust) can meet for the pollutant” (76 FR 1115). This 

option would constrain certain units’ allocations that, if based 

solely on historic heat input, would be determined by EPA to be “in 

excess of their reasonably foreseeable maximum emissions” under the 

Transport Rule programs (76 FR 1115).

As noted above, commenters offered numerous arguments in favor 

of using a historic heat input approach. These arguments apply 

equally to heat input option 1 and heat input option 2. EPA also 

received numerous comments comparing the two heat input options 

presented.

Many commenters preferred heat input option 1’s reliance purely 

on historic data as compared with heat input option 2’s reliance on 

that data modified by the application of EPA-determined “reasonable 

upper bound capacity factors” and “well-controlled emission rates.” 

Commenters also criticized the complexity of these modification 

factors in heat input option 2. While EPA believes both options 

represent viable approaches, the Agency agrees with commenters that 

the application of these factors increase the complexity of 

allocation determinations and would adjust unit-specific historic 

data by applying EPA-created factors generically determined for broad 

categories of units. 

Some commenters suggested that EPA’s application of these 

modification factors could also represent legal vulnerabilities for 
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the Transport Rule. In particular, they were concerned that the 

capacity factors and well controlled emission rates presented as part 

of heat input option 2 could be perceived as arbitrary. While EPA 

does not agree that these modification factors are arbitrary, the 

Agency does recognize that application of such EPA-created generic 

factors in determining unit-specific allocations increases the 

complexity of the allocation approach and raises issues regarding 

whether such generic factors are appropriately applied to each 

individual unit. 

iv. General comments on EPA’s authority to allocate allowances

Numerous commenters also noted that EPA has generally broad 

authority in selecting an allocation methodology under CAA sections 

110(a)(2)(D)(i)(I) and 302(y).80 EPA agrees with commenters that the 

Agency has broad discretion in this area. Neither the CAA nor the 

D.C. Circuit Court’s opinion in North Carolina specifies a particular 

methodology that EPA must use to allocate allowances to individual 

units. CAA section 110(a)(2)(D)(i)(I) requires prohibition of 

emissions “within the state” that significantly contribute to 

nonattainment or interfere with maintenance and gives states broad 

 

80 CAA section 302(y) defines the term “Federal implementation plan” 

as “a plan (or portion thereof) promulgated by the Administrator to 

fill all or a portion of a gap or otherwise correct all or a portion 

of an inadequacy in a State implementation plan, and which includes 

enforceable emission limitations or other control measures, means or 

techniques (including economic incentives, such as marketable permits 

or auctions of emissions allowances), and provides for attainment of 

the relevant national ambient air quality standard.”
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discretion to develop a control program in a SIP that achieves this 

objective. EPA has similarly broad discretion when issuing a FIP to 

realize this objective. Moreover, while the definition of FIP in CAA 

section 302(y) clarifies that a FIP may include “enforceable emission 

limitations or other control measures, means or techniques (including 

economic incentives, such as marketable permits or auctions of 

emissions allowances),” this section does not require EPA to use any 

particular methodology to allocate allowances under a FIP trading 

program. In light of this lack of direction in the CAA concerning 

allowance allocation, EPA has broad discretion to select an 

allocation methodology that is reasonable and consistent with the 

goals of CAA section 110(a)(2)(D)(i)(I).

The body of public comment makes it clear that no allocation 

option could be deemed satisfactory from the perspective of all 

stakeholders. Public comments from most states and industrial 

stakeholders with a substantial interest in how EPA allocates 

allowances under the Transport Rule FIPs expressed support for an 

historical heat input-based approach as opposed to the proposal’s 

emission-based approach. Most commenters favored this historical 

heat input data basis as the most sound and offered technical data 

corrections, which EPA considered and generally used in the final 

rule. EPA believes it is reasonable to select a heat input-based 

approach for the final Transport Rule because this approach is

consistent with the rule’s statutory objectives and has been found, 
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when implemented in prior trading programs, to be a credible, 

workable allocation approach.

b. Final FIP Allocation Methodology 

After consideration of all comments, EPA decided to allocate 

allowances to individual units based on that units’ share of the 

state’s historic heat-input, but to ensure that no unit’s allocations 

exceed that unit’s historic emissions. EPA decided to use the 

allocation methodology originally presented as heat input option 2, 

modified in response to public comments. EPA decided to use heat 

input option 2 but without the application of the “reasonable upperbound capacity utilization factor and a well-controlled emission 

rate” factors. This allocation approach reflects the Agency’s 

response to extensive public comment on the options presented in the 

proposed Transport Rule and subsequent NODAs and is a logical 

outgrowth of those actions. EPA is using this approach to allocate 

allowances under the FIPs for all four trading programs. Further 

details on the calculation and implementation of this approach are 

provided below in section VII.D.1.c and can also be found in the 

Allowance Allocation Final Rule TSD in the docket for this 

rulemaking. 

The principal reasons for this decision are:

 EPA believes that existing-unit allowance allocation under 

the Transport Rule should not generally advantage or 

disadvantage units based on the selection of fuels consumed 

or of pollution controls installed at a given unit in 
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anticipation of either the Clean Air Interstate Rule or the 

Transport Rule, i.e. fuel or control decisions taken from 

2003 onward. An approach that does not advantage or 

disadvantage units in this way avoids allocating in a way 

that would effectively penalize units that have already 

invested in cleaner fuels or other pollution reduction 

measures that will continue to deliver important emission 

reductions under this rulemaking. The approach selected in 

the final rule generally does not penalize such units and 

is thus generally fuel-neutral and control-neutral in its 

allocation determinations.

 EPA finds that the selected approach maximizes transparency 

and clarity of allowance allocations. EPA has already made 

public the historic heat input and historic emissions data 

on which this approach is based, and its application to 

calculate unit-level allocations in each state under that 

state’s emission budgets finalized in this Transport Rule 

can be relatively easily replicated.

 EPA finds that quality-assured historic CEMS-quality data 

used to implement this approach represent the most 

technically superior data available to EPA at the time of 

this rulemaking for calculating unit-level allocations. 

The selected approach relies on unmodified historic data 

reported directly by the vast majority of covered sources, 
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whose designated representatives have already attested to 

the validity and accuracy of this data. EPA agrees with 

commenters that allowance allocations should be based on 

quality-assured data to the maximum extent possible. This 

approach uses the most accurate data currently available to 

EPA.

 Heat-input based approaches were used to allocate 

allowances under both the NOX Budget Trading Program and the 

Acid Rain Program. Allocation under these programs was 

readily and easily administered, and the programs achieved 

or exceeded their environmental goals. The selected 

approach’s use of heat input as a basis for allocations 

builds on prior legislative and administrative approaches 

to allowance allocations for trading programs.

 EPA also finds that the selected approach’s addition of a 

constraint to heat input-based allocations where such 

allocations would otherwise exceed a unit’s maximum 

historic emissions is a reasonable extension of a heat 

input-based allocation approach. The Transport Rule 

trading programs are established to achieve overall 

emission reductions in each covered state. As a group, 

covered sources within each state must make the necessary 

reductions under these programs. In light of each 

program’s goal to reduce each state’s overall emissions, it 
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is logical and consistent with that goal that the starting 

point for each source under these programs –- i.e., the 

initial allocations of shares of the state budget to 

covered units -- be an amount of allowances no greater than 

each unit’s maximum historic emissions. Under the trading 

programs, any source may emit a ton of SO2 or NOX for which 

it holds a corresponding allowance, which it may acquire 

either by initial allocation or by subsequent purchase, to 

the extent consistent with the assurance provisions 

(discussed elsewhere in this preamble) that ensure 

achievement of the requisite overall reductions in each 

state. Consequently, the initial allocations to the units 

at each source are the starting point for each source’s 

efforts to comply with the allowance-holding and assurance 

provision requirements, but do not determine the source’s 

strategies for compliance and ultimate level of emissions. 

EPA believes that a starting point of unit-level heat 

input-based allocations constrained not to exceed each 

specific units’ maximum historic emissions is reasonable 

and consistent with the program goals of reducing overall 

emissions in each state: each existing unit is allocated an 

amount that either reflects reduced unit emissions or does 

not exceed historic emissions, and, from that starting 

point, the units, as a group, reduce overall emissions to 

the level required for each state. Conversely, EPA 
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believes that a starting point allocating some units more 

than they have ever emitted would be illogical in programs 

aimed at reducing overall emissions.

EPA believes that this selected allocation methodology for the 

final Transport Rule FIPs is within its authority under the Clean Air 

Act. Section 110(a)(2)(D)(i)(I) of the CAA requires that emissions 

“within a state” that significantly contribute to nonattainment or 

interfere with maintenance in another state be prohibited. In the 

final Transport Rule, EPA analyzed each individual state’s 

significant contribution and interference with maintenance and 

calculated budgets that represent each state’s emissions after the 

elimination of prohibited emissions in an average year. The 

methodology used to allocate allowances in a state budget to 

individual units in the state has no impact on that state’s budget or 

on the requirement that the state’s emissions not exceed that budget 

plus variability. Regardless of the allocation methodology used, the 

state’s responsibility for eliminating its significant contribution 

and interference with maintenance remains unchanged. This is 

reflected by the fact that allocations under each state’s budget, 

regardless of how they are made, cannot change that state’s budget. 

In sum, the allocation methodology has no impact on the final rule’s 

ability to satisfy the statutory mandate of CAA section 

110(a)(2)(D)(i)(I) to eliminate significant contribution to 

nonattainment and interference with maintenance.
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Consistent with its broad authority in CAA sections 

110(a)(2)(D)(i)(II) and 302(y), EPA believes that data quality, fuelneutrality, control-neutrality, transparency, clarity, consistency 

with program goals, and successful experience in previous trading 

programs are reasonable factors on which to base the selection of an 

allowance allocation methodology for existing units for the final 

Transport Rule. EPA believes that the transparency and clarity of 

this allocation approach builds credibility with the public that the 

government is distributing a public resource -– i.e., allowances --

precisely as stated in this rulemaking, with clear execution that can 

be relatively easily verified.

EPA also believes that the final Transport Rule’s heat inputbased approach for existing units is consistent with the goals of the 

Clean Air Act because it allocates allowances to existing units on 

the basis of a neutral factor that does not advantage or disadvantage 

a unit based on what fuel the unit burns or whether or not a unit has 

installed controls in anticipation of these regulations. In 

contrast, allocations under the proposal’s emission-based methodology 

would give a greater share of allowances to units with higher 

emission rates, which are generally responsible for a greater share 

of a state’s total emissions. Because these higher-emitting rate 

units are generally responsible for a greater share of emissions, it 

follows that they are also responsible for a greater share of a 

state’s significant contribution to nonattainment and interference 

with maintenance. The proposal’s emission-based allocation 
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methodology would disadvantage one of two otherwise identical 

existing units if it invested in emission reductions in anticipation 

of the Clean Air Interstate Rule or this final Transport Rule. 

The heat-input allocation methodology selected for the final 

Transport Rule does not have this flaw. In contrast to the 

proposal’s emission-based allocation approach, the heat input 

allocation methodology selected by EPA yields a smaller proportion of 

allowances relative to emissions to higher-emission-rate units and a 

higher proportion of allowances relative to emissions to loweremission-rate units. For example, assume that in a state with two 

units and in a baseline year, Unit A combusts 100 mmBtu of heat input 

and emits 1,000 tons while Unit B combusts 100 mmBtu of heat input 

and emits only 500 tons. Assume also that this state’s future 

Transport Rule emissions budget for this pollutant is only 500 tons. 

Because Units A and B each make up an even share of historic heat 

input for the state, the final rule’s heat input-based approach would 

allocate the same share of allowances (250 tons) to each unit. In 

this example, Unit A’s initial allocation of 250 is a smaller 

proportion of its historic emissions (25 percent of its baseline 

1,000-ton emissions), while Unit B’s initial allocation of 250 is a 

larger proportion of its historic emissions (50 percent of its 

baseline 500-ton emissions). Therefore, Unit B’s ability to emit 

fewer tons per mmBtu of heat content used for generating electricity 

(as compared with Unit A) results in Unit B receiving a larger 
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proportion of its historic emissions as an initial allocation share 

than Unit A receives.

This relative distributional pattern yielded is consistent with 

the goals of CAA section 110(a)(2)(D)(i)(I) because under this 

distribution, higher-emitting units, which are responsible for a 

greater share of the state’s significant contribution to 

nonattainment and interference with maintenance, would require 

relatively more allowances in order to cover their pre-existing 

emissions than would lower-emitting units. EPA believes this initial 

allocation pattern is an appropriate reflection of the goals of CAA 

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

The heat input-based allowance methodology selected by EPA is 

fuel-neutral, control-neutral, transparent, based on reliable data, 

and similar to the allocation methodologies used in the NOX SIP Call 

and Acid Rain Program. For all these reasons, EPA determined that it 

is appropriate to use a heat input-based allocation methodology in 

this rule.

In addition, this allocation methodology is similar to an 

output-based allocation approach, which would base allocations on the 

quantity of electricity generated (rather than energy content 

combusted) and would also be fuel-neutral, control-neutral, and able 

to reward generation units that operate the most efficiently. Many 

state and industry commenters advocated using an output-based

approach due to its reported strong value in promoting efficiency. 

However, at this time EPA does not have access to unit-level output 
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data that is as quality-assured or comprehensive as its data sets on 

heat input across the units considered. Therefore, EPA is using a 

heat input-based approach under the Transport Rule in part due to its 

ability to serve as a reasonable proxy for an output-based standard 

using the most quality-assured data that EPA has to date.

In the NODA, EPA noted that final state budgets and allocations 

may differ from the proposed budgets and allocations because EPA was 

still in the process of updating its emission inventories and 

modeling in response to public comments, including comments on IPM. 

Thus, unit-level allocations in the NODA provided an indication of 

the proportional share of a state’s budget that would be allocated to 

individual existing units if the alternative methodologies were used. 

The allocations made final today are based on budgets that reflect 

the updated modeling and comments received during the comment period. 

c. Calculation of Existing Unit Allocations Under the Final Transport 

Rule FIPs

Allocations under this final methodology for each existing unit are 

determined by applying the following steps.

1. For each unit in the list of potential existing Transport Rule 

units, annual heat input values for the baseline period of 2006 

through 2010 are identified using data reported to EPA or, where 

EPA data is unavailable, using data reported to the Energy 

Information Administration (EIA). For a baseline year for which 

a unit has no data on heat input (e.g., for a baseline year 
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before the year when a unit started operating), the unit is 

assigned a zero value. (Step 2 explains how such zero values 

are treated in the calculations.) The allocation method uses a 

5-year baseline to approximate a unit’s normal operating 

conditions over time. 

2. For each unit, the three highest, non-zero annual heat input 

values within the 5-year baseline are selected and averaged. 

Selecting the three highest, non-zero annual heat input values 

within the five-year baseline reduces the likelihood that any 

particular single year’s operations (which might be negatively 

affected by outages or other unusual events) would determine a 

unit’s allocation. If a unit does not have three non-zero heat 

input values during the 5-year baseline period, EPA averages 

only those years for which a unit does have non-zero heat input 

values. For example, if a unit has only reported data for 2008 

and 2009 among the baseline years and the reported heat input 

values are 2 and 4 mmBtus respectively, then the unit’s average 

heat input used to determine its pro-rata share of the state 

budget is (2+4)/2 = 3.

3. Each unit is assigned a baseline heat input value calculated as 

described in step 2, above, referred to as the “3-year average 

heat input.”
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4. The 3-year average heat inputs of all covered existing units in 

a state are summed to obtain that state’s total “3-year average 

heat input.”

5. Each unit’s 3-year average heat input is divided by the state’s 

total 3-year average heat input to determine that unit’s share 

of the state’s total 3-year average heat input.

6. Each unit’s share of the state’s total 3-year average heat input 

is multiplied by the existing-unit portion of the state budget 

(i.e., the state budget minus the state’s new unit set-aside 

and, if applicable, minus the Indian country new unit set-aside) 

to determine that unit’s initial allocation. 

7. An 8-year (2003-2010) historic emissions baseline is established 

for SO2, NOX, and ozone-season NOX based on data reported to EPA 

or, where EPA data is unavailable, based on EIA data. This 

approach uses this 8-year historic emissions baseline in order 

to capture the unit-level emissions before and after the 

promulgation of CAIR.

8. For each unit, the maximum annual historic SO2 and NOX emissions 

are identified within the 8-year baseline. Similarly, the 

maximum ozone season NOX emissions from the 8-year baseline for 

each unit are identified. These values are referred to as the 

“maximum historic baseline emissions” for each unit.
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9. If a unit has an initial historic heat-input based allocation 

(as determined in step 6) that exceeds its maximum historic 

baseline emissions (as determined in step 8), then its 

allocation equals the maximum historic baseline emissions for 

that unit.

10.The difference (if positive) under step 9 between a unit’s 

historic heat-input-based allocation and its “maximum historic 

baseline emissions” is reapportioned on the same basis as 

described in steps 1 through 6 to units whose historic heatinput-based allocation does not exceed its maximum historic 

baseline emissions. Steps 7, 8, and 9 are repeated with each 

revised allocation distribution until the entire existing-unit 

portion of the state budget is allocated. The resulting 

allocation value is rounded to the nearest whole ton using 

conventional rounding.

Table VI.D-1 below provides an illustrative application of the 

steps 1-10 in a hypothetical state.

Table VI.D-1: Demonstration of Allocations Using Final 

Allocation Methodology

in a Three-Unit State with an 80-Ton State Budget

Steps 1-6 Steps 7,8,9

Steps 1-9 

Reiterated Step 10

Initial 

Historic Heat 

Input-based 

Allocation

Maximum 

Historic 

Baseline 

Emissions

Revised 

Historic 

Heat 

Inputbased 

Allocation Final Allocation
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Unit 

A 20 16 N/A 16

Unit 

B 30 50 32 32

Unit 

C 30 50 32 32

2. Allocations to New Units

EPA is finalizing -- similar to the proposal (75 FR 45310) -- an 

approach to allocate emission allowances to new units from new unit 

set-asides in each state. A “new unit” may be any of the following: 

(1) a covered unit commencing commercial operation on or after 

January 1, 2010; (2) any unit that becomes a covered unit by meeting 

applicability criteria subsequent to January 1, 2010; (3) any unit 

that relocates into a different state covered by the Transport Rule;81

and (4) any existing covered unit that stopped operating for 2

consecutive years but resumes commercial operation at some point 

thereafter. 

The proposed Transport Rule would have required that owners and 

operators initially request allowances from the new unit set-aside 

when the unit first became eligible for an allocation. EPA now 

 

81

 Existing- or new-unit allocations drawn from the budget of the 

relocated unit’s original state are replaced by new unit set-aside 

allocations from the budget of the unit’s relocation state in order 

to generally ensure that allocations are drawn from the correct state 

budget. 
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believes that it can identify which units become eligible and when 

they become eligible, based on information provided in other 

submissions (e.g., certificates of representation, monitoring system 

certifications, and quarterly emissions reports) that the final rule 

already requires such units to make to EPA. EPA concludes that 

requiring owners and operators to submit requests of new unit setaside allocations would impose an unnecessary burden on the owners 

and operators, as well as on EPA, and therefore EPA has removed this 

requirement in the final rule.

The following sections describe the methodology in the final 

Transport Rule for allocating to new units, how EPA determined the 

size of new unit set-asides in the final rule, and how EPA has 

provided for allocations to new units that locate in Indian Country.

a. New Unit Allocation Methodology

The proposal’s new unit allocation methodology did not provide 

any allocation for a new unit’s first control period of commercial 

operation. Some commenters expressed concern about the lack of new 

unit allocations the first year of commercial operation. In order to 

address this concern, EPA is modifying the new unit allocation 

methodology in this final rule to include allocations to new units 

for the first control period in which the units are in commercial 

operation, as well as for control periods in subsequent years.

The final rule’s allocation to new units is performed in two 

“rounds.” The first round is the same as the new unit allocation 

procedures in the proposal (except for elimination of the 
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requirements that owners and operators request the allocations) and 

occurs during the control period for which the allocations are made. 

These first round allocations are based on new unit emissions during 

the prior control period and are recorded in allowance accounts in 

the Allowance Management System for the units by August 1 of each 

control period. For example, for the 2012 vintage year, “firstround” allocations would be made to new units by August 1, 2012 based 

on their emissions in the 2011 control period (as monitored and 

reported in accordance with Part 75 of the Acid Rain Program 

regulations). If the new unit set-aside is insufficient to 

accommodate first round allocations reflecting all new units’ prior 

control period emissions, the first round allocations are made pro 

rata to new units based on their share of total new unit emissions in 

the prior control period.

The second round of allocations accommodates new units that come 

online during the control period for which the allocations are made 

and did not therefore receive any allocation in the first round. The 

second round also accommodates new units that come online partway 

into the prior control period and therefore received an allocation in 

the first round that did not extend to cover operations in a full 

control period. This second round of new unit allocation is 

therefore applicable only to new units coming online either during 

the control period of the allocation or during the control period 

immediately prior. New units coming online earlier than the previous 

control period only receive first-round allocations from the new unit 
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set-asides, as first-round allocations to those units are based on 

operational data spanning an entire control period.

Second-round allocations are based on new unit emissions during 

the same control period as the vintage year of the allowances 

allocated. For example, for the 2012 vintage year, “second-round” 

allocations are based on the difference between the new unit’s 

emissions in the 2012 control period and the new unit allocation (if 

any) that the unit received in the first round of allocations. For a 

unit coming online in 2012, this amount equals its total emissions 

during the 2012 control period. For a unit coming online in 2011, 

this amount equals its incremental emissions in 2012 beyond its 

emissions in 2011, as such a unit would have already received a 

first-round allocation from the new unit set-aside based on its 

emissions in 2011. Second-round allocations are recorded in 

allowance accounts by November 15 for the NOX ozone season trading 

program (ahead of the December 1 compliance deadline) and by February 

15 of the following calendar year for NOX and SO2 annual trading 

programs (ahead of the March 1 compliance deadline).

This methodology only allocates in the second round whatever 

allowances remain in the new unit set-asides after the first-round 

allocations have been recorded. If the new unit set-aside available 

for second round allocations is insufficient to accommodate 

allocations based on the difference between control period emissions 

and any first round allocations for the units involved, then the 
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second round allocations are made pro rate to the new units based on 

their share of the total of such differences. 

b. Determination of New Unit Set-Asides

The proposed Transport Rule identified new units using a 

threshold online date of January 1, 2012, whereas the final Transport 

Rule uses a threshold online date of January 1, 2010. As explained 

above, EPA adjusted this cutoff date because the final Transport 

Rule’s allocation methodology for existing units requires that EPA 

possess at least 1 full year of historic data in order to calculate 

allocations. As a consequence, EPA recognizes that the proposal’s 

methodology to determine the size of the new unit set-asides based 

only on new EGUs forecast by the model would fail to account for 

known EGUs that have come online, or are planned to come online, 

after January 1, 2010. Therefore, EPA has modified its approach to 

determining the size of the new unit set-asides in the final rule to 

account for both “potential” units (i.e., those that are not yet 

planned or under construction but are projected by modeling to be 

built) and ”planned” units (i.e., those that are known units with 

planned online dates after January 1, 2010). EPA uses the 

distinction between “potential” and “planned” new units to determine 

the ultimate size of each state’s new unit set-aside (as a percentage 

of that state’s budgets for each pollutant covered); however, the new 

unit allocation methodology described above applies the same to 

“potential” and “planned” new units.
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The first step of EPA’s analysis to determine the new unit setasides accounts for likely future emissions from potential units, and 

its methodology is taken directly from the Transport Rule proposal 

but reflects updated modeling (see “Allowance Allocation to Existing 

and New Units under the Transport Rule Federal Implementation Plans” 

TSD for detailed findings). This analysis informed EPA’s decision to 

establish a minimum new unit set-aside size of 2 percent of each 

state’s budget for each pollutant that is configured to accommodate 

future emissions from potential units. 

For the final rule, EPA augmented its new unit set-aside 

determination to account for “planned” units through an additional 

step. Because the location of these “planned” units is known and 

identified in EPA modeling, this second step is a state-specific 

modification of the size of the new unit set-asides. That is, EPA 

only increased new unit set-asides above the 2 percent minimum 

established in the first step for states that had additional known 

units coming online between January 1, 2010, and January 1, 2012. 

The increases made to the new unit set-asides for these planned 

units reflect the projected emissions from these units. Therefore,

if the expected emissions of a given pollutant from all “planned” new 

units in a given state were equal to 3 percent of that state’s budget 

for that pollutant, then EPA added that amount to the base 2 percent

new unit set-aside (creating a hypothetical new unit set-aside of 5

percent for that pollutant in that state). See “Allowance Allocation 

to Existing and New Units under the Transport Rule Federal 
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Implementation Plans” TSD for detailed results showing how EPA 

determined the size of each new unit set-aside reflecting the 

application of both of the steps described above. This approach to 

determining the size of state new unit set-asides is a logical 

outgrowth of the proposal, the NODA on allowance allocations, and 

updated modeling results. In fact, EPA received comments that using 

a January 1, 2010 cutoff date for distinguishing between existing and 

new units would result in the new unit set-aside, as proposed, being 

insufficient to meet the needs of units already under construction. 

EPA believes that the approach adopted in the final rule results in 

new unit set-asides that reasonably accommodate the foreseeable 

emissions from both planned and potential new units in each state. 

The new unit allocation percentages for each state are shown in 

Table VII.D.2-1.

Table VII.D.2-1: Percentage of State Emission Budgets for Allowances 

in State New Unit Set-Asides

Annual SO2 Annual NOX OzoneSeason NOX

Alabama 2% 2% 2%

Arkansas --- --- 2%

Florida --- --- 2%

Georgia 2% 2% 2%
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Illinois 5% 8% 8%

Indiana 3% 3% 3%

Iowa 2% 2% ---

Kansas 2% 2% ---

Kentucky 6% 4% 4%

Louisiana --- --- 3%

Maryland 2% 2% 2%

Michigan 2% 2% ---

Minnesota 2% 2% ---

Mississippi --- --- 2%

Missouri 2% 3% ---

Nebraska 4% 7% ---

New Jersey 2% 2% 2%

New York 2% 3% 3%

North Carolina 8% 6% 6%

Ohio 2% 2% 2%

Pennsylvania 2% 2% 2%

South Carolina 2% 2% 2%
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Tennessee 2% 2% 2%

Texas 5% 3% 3%

Virginia 4% 5% 5%

West Virginia 7% 5% 5%

Wisconsin 5% 6% ---

c. Procedures for Allocating New Unit Set-asides

For the first round of new unit set-aside allocations, the 

Administrator will promulgate a notice of data availability informing 

the public of the specific new unit allocations and provide an 

opportunity for submission of objections on the grounds that the 

allocations are not consistent with the requirements of the relevant 

final rule provisions. A second notice of data availability will 

subsequently be promulgated in order to make any necessary 

corrections in the specific new unit allocations. As discussed 

elsewhere in this preamble, the final rule establishes a different 

schedule for promulgation of these notices of data availability than 

the proposed rule. In particular, a single set of deadlines (i.e., 

for the first notice in the first round of allocations, June 1 of the 

year for which the new unit allocations are described in the notice 

and, for the second notice of the first round, August 1 of that year) 

for promulgation of the notices is established for all of the 

Transport Rule trading programs. EPA believes that these deadlines 
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will provide sufficient time for EPA to obtain final emissions data 

for the prior year for the units involved and to calculate the 

allocations and promulgate the notices. Further, the approach of 

using the same deadline for all of the Transport Rule trading 

programs will simplify EPA’s implementation and reduce the complexity 

of the process for source owners and operators.

For the second round of new unit set-aside allocations, the 

Administrator will also promulgate two notices of data availability. 

However, the deadlines for the notices differ for the NOX ozone season 

trading program and for the SO2 and NOX annual trading programs 

because control period emissions data (used in making second round 

allocations) become available sooner, and the compliance deadline for 

holding allowances covering emissions is sooner, in the NOX ozone 

season trading program. The control period in the NOX ozone season 

program ends on September 30, and fourth quarter emissions reports 

must be submitted to EPA by October 30, while the control periods in 

the SO2 and NOX annual programs end on December 31 and fourth quarter 

emission reports are due by January 30. Further, in order for the 

second round allocations to be available to be used for compliance 

with the allowance-holding requirement, the second round needs to be 

completed before the compliance dates, which are December 1 in the NOX

ozone season program and March 1 in the SO2 and NOX annual programs. 

Consequently, for the NOX ozone season program the Administrator will 

promulgate by September 15 a notice of data availability identifying 

the units eligible for second round allocations and by November 15 a 
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second NODA of the list of eligible units and their second round 

allocations, which will also be recorded in the allowance accounts by 

that date. The comparable deadlines for the SO2 and NOX annual 

programs are December 15 and February 15. EPA believes that these 

deadlines will provide sufficient time for EPA to identify the units 

and obtain their needed emissions data and to calculate the 

allocations and promulgate the notices.

d. Addition of Allowances to New Unit Set-asides

As discussed elsewhere in this preamble, EPA proposed that, if a 

unit with an existing-unit allocation does not operate for 3

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 set-aside 

for the state in which the retired unit is located. EPA is retaining 

this provision in the final rule but is changing the time of nonoperation to 2 years and the time of allowance allocation to a nonoperating unit to 4 years. Starting in the fifth year of nonoperation, allowances will be allocated to the new unit set-aside for 

the state in which the non-operating unit is located. 

EPA received comments that the new unit set-asides were not 

sufficient to encourage the operation of new units. One commenter 

suggested that allowance allocations should cease after 3 years of 

non-operation because the financial incentive gained from receiving 

allowances beyond the 3-year period is insignificant relative to 

operating and fuel costs. Another commenter said that providing 
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allowances to non-operating units is unnecessary and distorts the 

market. 

In addition to increasing the size of the new unit set-aside in 

this final rule, as described above, EPA is terminating existing unit 

allocations starting in the fifth year after the unit does not 

operate for 2 consecutive years and reallocating to the new unit setaside the allowances that the unit otherwise would have received for 

the fifth and subsequent years in order to make them available for 

new units in the state. This approach allows the new unit set-asides 

to grow over time. 

e. Allocations to New Units Locating in Indian Country

EPA received several comments on the proposed rule that it did 

not explicitly address the distribution of allowances to potential 

new units built in Indian country. EPA recognized this concern and 

requested comment on this topic in the January 7, 2011 NODA.

In the final rule, EPA is providing a mechanism to make 

allowances available in the future for new units built in Indian 

country. The final rule establishes an Indian country new unit setaside for each pollutant in each state whose borders encompass Indian 

country (i.e., Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, 

Mississippi, Nebraska, New York, North Carolina, South Carolina, 

Texas, and Wisconsin). EPA will retain administration of these 

Indian country new unit set-asides as part of the Transport Rule 

trading programs whether or not a Transport Rule state elects to 

modify or replace the Transport Rule FIPs through approved SIP 
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revisions. EPA does not create Indian country new unit set-asides 

for states lacking Indian country within their borders. 

EPA determined the size of each Indian country new unit setaside by calculating the ratio of square mileage of Indian country to 

the square mileage of the state within whose borders Indian country 

is located. This calculation yielded a maximum percentage of 5 

percent when assessing all of the states encompassing Indian country 

subject to the final Transport Rule; this is referred to as the “5 

percent Indian country factor” below. To determine the maximum 

percentage, EPA used the American Indian Reservations/Federally 

Recognized Tribal Entities dataset, which contains data for the 562 

federally recognized tribal entities in the contiguous U.S. and 

Alaska. EPA accessed the data to analyze the Transport Rule region 

and compare the square miles of Indian country with the square miles 

of the Transport Rule state that includes the Indian country. EPA 

then took the highest percentage as the number to be applied across 

all states with Indian country to determine the size of the Indian 

country new unit set-aside pertinent to that state’s budgets under 

the Transport Rule. EPA chose to use the maximum percentage (5 

percent) from the Indian country analysis to determine the Indian 

country set-aside for each state on the basis that this approach 

would reserve a reasonable number of allowances from each state’s 

budget for potential allocation to new units that may locate in 

Indian country within that state’s borders. Any allowances from the 

Indian country new unit set-aside that are not allocated in a given 
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control period are redistributed into the state’s new unit set-aside. 

As discussed above, any allowances not allocated from that new unit 

set-aside are redistributed to existing units based on the existing 

units’ share of the total existing unit allocations.

To calculate the size of each tribal new unit set-aside, EPA 

applied this 5 percent Indian country factor to the portion of the 

state’s new unit set-aside originally determined by accounting for 

“potential” new units, which as described above was set at 2 percent

of each pollutant’s budget in each state. Therefore, the Indian 

country new unit set-aside is 5 percent of 2 percent of a state’s 

budget, or 0.1 percent of that total state budget. EPA did not apply 

the 5 percent Indian country factor to the state-specific planned 

unit portion of each state’s new unit set-aside because the planned 

unit portion is determined using projected emissions from specific, 

known units coming online after January 1, 2010, and none of these 

known units are located in Indian country.

The Indian country new unit set-asides in the following 

Transport Rule states with Indian Country are shown in Table VII.D.2-

2.

Table VII.D.2-2: New Unit Set-Aside Allowances for Indian Country 

(tons)

SO2

2012-

2013

SO2 

2014 

and 

Beyond

Annual

NOX 

2012-

2013

Annual

NOX 

2014 

and 

Beyond

OzoneSeason 

NOX 

2012-

2013

OzoneSeason 

NOX

2014

and 

Beyond

Florida --- --- --- --- 28 28

Iowa 107 75 38 38 --- ---
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Kansas 42 42 31 26 --- ---

Louisiana --- --- --- --- 13 13

Michigan 229 144 60 58 --- ---

Minnesota 42 42 30 30 --- ---

Mississippi --- --- --- --- 10 10

Nebraska 65 65 26 26 --- ---

New York 27 19 18 18 8 8

North 

Carolina

137 58 51 42 22 18

South 

Carolina

89 89 32 32 14 14

Texas 244 244 134 134 63 63

Wisconsin 80 40 32 30 --- ---

Under the FIPs, EPA allocates allowances from Indian country new 

unit set-asides in essentially the same manner as it allocates 

allowances from state new unit set-asides. The approach for 

identifying, and determining the number of allowances allocated to,

new units in Indian country is the same as the approach for 

identifying and determining allocations for non-Indian country new 

units covered by the state new unit set-aside, and allocations are 

made in two rounds using the same schedules for promulgation of 

notices of data availability. However, as discussed above, 

unallocated allowances in the Indian country set-asides are handled 

differently from unallocated allowances in the state new unit setasides in that unallocated Indian country new unit set-aside 

allowances are first transferred back into the state new unit setaside and then, if still not allocated to new units, are distributed 

to existing units in the state. EPA believes that the above-
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described approach in establishing and handling the Indian country 

new unit set-asides and state new unit set-asides is a reasonable way 

of making a sufficient amount of allowances available for new units 

in the state and Indian country located in the state and ensuring 

that the entire state budget is available to either new or existing 

units in the state and Indian country. EPA retains administration of 

these Indian country new unit set-asides (and, of course, the 

portions of state budgets that comprise these set-asides) as part of 

the Transport Rule trading programs even if a state elects to modify 

or replace the Transport Rule FIPs through approved SIP revisions. 

EPA continues to manage and distribute the Indian country new unit 

set-aside allowances in the same manner as under the FIPs. 

Unallocated allowances in the Indian country new unit set-aside will 

be returned to the portion of the state budget allocated under the 

approved SIP’s allocation provisions. EPA believes that this 

approach is reasonable because EPA, rather than the states, has the 

authority and responsibility of administering the Transport Rule with 

regard to new units that locate in Indian country.

E. Assurance Provisions

To ensure that the FIPs require the elimination of all emissions 

that EPA has identified that significantly contribute to 

nonattainment or interfere with maintenance within each individual 

state, the Agency is adopting assurance provisions in addition to the 

requirement that sources hold allowances sufficient to cover their 

emissions. These assurance provisions limit emissions from each 
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state to an amount equal to that state’s trading budget plus the 

variability limit for that state (i.e., the state assurance level). 

As discussed in section VI of this preamble, 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 to nonattainment and interference with 

maintenance are 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 to nonattainment and interference with maintenance. 

Starting in 2012, EPA is establishing, as part of the FIPs, 

limits on the total emissions that may be emitted from EGUs at 

sources in each state. For any single year, the state’s emissions 

must not exceed the state budget with the variability limit allowed 

for any single year for that state (i.e., the state’s 1-year 

variability limit). In 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 1 year (i.e., the state’s assurance level). EPA is not 

finalizing 3-year variability limits that were included in the 

proposal for the reasons explained previously in section VI.E of this 

preamble. The state budgets, variability limits, and state assurance 

levels for each state are shown in Tables VI.F-1, VI.F-2 and VI.F-3 
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in section VI.F of this preamble. The basis for the variability 

limits is also described in section VI.E of this preamble. 

Additional details may be found in the Power Sector Variability Final 

Rule TSD in the docket to this rule.

To implement this requirement, EPA first evaluates whether any 

state’s total EGU emissions in a control period exceeded the state’s 

assurance level. If any state’s EGU emissions in a control period 

exceed the state assurance level, then EPA applies additional 

criteria to determine which owners and operators of units in the 

state will be subject to an allowance surrender requirement. In 

applying the additional criteria, EPA evaluates which groups of units 

at the common designated representative (DR) level had emissions 

exceeding the respective common DR’s share of the state assurance 

level (regardless of whether the source had enough allowances to 

cover its emissions) during the control period.82 

The requirement that owners and operators surrender allowances 

under the assurance provisions will be triggered only if two criteria 

are met: (1) the group of sources and units with a common DR are 

located in a state where the total state EGU emissions for a control 

period exceed the state assurance level; and (2) that group with the 

common DR had emissions exceeding the respective DR’s share of the 

 

82 A group of one or more sources and units in a state has a common 

designated representative where the same individual is authorized as 

the designated representative (not the alternate designated 

representative) for that group of sources and units as of April 1 

immediately following the allowance transfer deadline for the control 

period involved.
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state assurance level. The share of the assurance penalty borne by 

the owners and operators will be based on the amount by which the 

total emissions for the units in the group exceed the common DR’s 

share of the state assurance level as a percentage of the total 

calculated for all such groups of sources and units in the state. 

Thus, the owners and operators of each such group of sources and 

units must surrender an amount of allowances equal to the excess of 

state EGU emissions over the state assurance level multiplied by the 

owners’ and operators’ percentage and multiplied by two (to reflect 

the penalty of two allowances for each ton of the state’s excess EGU 

emissions). See Table VII.E-1 below for an illustrative example.

This approach in the final rule of implementing the assurance 

provisions on a common designated representative basis contrasts with 

the approach in the proposed rule of implementing the assurance 

provisions on an owner basis. In the January 7, 2011 NODA, EPA 

requested comment on the alternative of basing the assurance 

provision penalty using common designated representatives, and some

commenters supported this alternative. The common designated 

representative approach is simpler and avoids the need to collect 

information on percentage ownership (which information is not used in 

any other provisions of the Transport Rule trading programs). 

In addition, the common designated representative approach 

provides additional flexibility to owners and operators who have only 

one or a few units in a given state but have the option of selecting 

a common designated representative with owners and operators of other 
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units in the state. EPA expects companies in various states will 

readily be able to manage their emissions to stay collectively below 

their state’s assurance levels as they track emissions quarterly 

throughout the year and manage their generation units and pollution 

control efforts accordingly. However, if the state appears to be 

approaching its assurance level, this final rule also gives companies 

the ability to further ensure that they will not have excess 

emissions by combining multiple units under a common DR. This 

flexibility allows utilities to re-balance allowances and emissions 

to mitigate penalty risk if the state violates its assurance level. 

In a state that does not appear to risk violating its assurance level 

in a given period, utilities would not need to consider the assurance 

aspect of selecting DRs. However, EPA anticipates that in the event

utilities desire additional certainty or mitigation of assurance 

penalty risk, they will take advantage of this common DR provision or 

pursue similar private arrangements with each other to cover their 

emissions at the lowest possible cost.

While the DR provision could benefit utilities by allowing them 

to pool their penalty risk, the utilities would still be subject to 

the antitrust laws. As with any joint venture between competitors, 

the efficiency benefits of pooling risk would be weighed against any 

anticompetitive harm associated with DRs. 

 

This new feature in the final rule, in conjunction with the 

simplifications to the final rule’s variability limits described in 
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section VI.E, will give companies under the air quality-assured 

trading program greater flexibility in each state to determine the 

most cost-effective pattern of emission reductions while EPA ensures 

each state meets its assurance level needed to address the 

significant contribution in each state.

In the January 7, 2011 NODA, EPA also requested comment on 

continuing to link allocations to assurance provision allowance 

surrender requirements. Even though the final rule uses a different 

allowance allocation methodology than the allocation methodology that 

was proposed, the final rule continues to treat the groups of units 

with greater emissions than their allocations plus share of state 

variability as responsible for the state’s excess of emissions over 

the state assurance level. EPA believes that this approach is 

reasonable because any state that exceeds its state assurance level 

likely does so because not all units have made the reductions 

necessary to eliminate the state’s contribution to nonattainment or 

interference with maintenance. Moreover, the groups of units with 

emissions exceeding their allocations plus share of variability are 

the units most likely to have contributed to the state’s exceedance 

of its state assurance level and thus to the state’s triggering of 

the assurance provisions. Consequently, EPA concludes that it is 

reasonable to penalize owners and operators of those sources and 

units (grouped by common DR) for the state’s exceedance through 

application of the assurance provision allowance surrender 
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requirement. Some commenters stated that this is a reasonable 

approach. 

While a few commenters suggested alternative approaches to the 

assurance provisions, EPA believes that the suggested alternatives 

are not workable and are likely to create implementation problems. 

These commenters suggested variations of approaches that would have 

created state-specific and vintage year-specific allowances that 

would have been traded independently of compliance allowances. These 

differentiated allowances would have fragmented the allowance markets 

and made the programs resemble the intrastate trading option that EPA 

rejected because of market power and other concerns described in the 

proposal.

The existence of the assurance provisions with significant 

penalties imposed if a state’s emissions exceed the state budget with 

the variability limit, along with other features of the Transport 

Rule trading programs discussed below, will ensure that state 

emissions stay below the level of the budget with the variability 

limit. In making compliance decisions and determining to what extent 

to rely on purchased or banked allowances, owners and operators will 

have to take into account the risk of triggering the assurance 

provisions in the state involved and of incurring significant 

assurance provision penalties. The greater the extent to which units 

sharing a common DR have emissions exceeding the DR units’ 

allocations plus share of the state variability limit, the greater 

the risk of being subject to the assurance provision penalties. 
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As discussed previously in section VII.D.2, EPA allocates 

allowances to a new unit for the control period during which the unit 

commences commercial operation from the new unit set-aside based on 

its emissions. In the case where assurance provisions for a state 

are triggered in the year that a new unit commences operation, the 

unit’s share of the state assurance level is calculated using the 

unit’s allocation from the new unit set-aside plus its proportional 

share of the variability limit. There is the possibility that a new 

unit would receive no allocation for the control period during which 

the unit commences commercial operation. EPA sees no reasonable 

basis for disadvantaging owners and operators because they started up 

a new unit and EPA had no emissions data on which to base an 

allocation from the new unit set-aside or no allowances were 

available for the unit in the state’s new unit set-aside.83 For these 

new units, EPA would use a specific surrogate number to calculate the 

maximum amount of emissions that the unit would likely have had 

during that year. The surrogate emission number applies only if the 

state’s assurance provisions are triggered and only in the first year 

of the new unit’s commercial operation for a new unit that did not 

receive an allocation from the set-aside. The methodology for 

calculating the surrogate emission number is essentially unchanged 

 

83 Some other units (e.g., those units with no data for the 2006-2010 

base period) may have a zero allocation for a control period. 

However, those are highly likely to be units that will continue to 

operate rarely or not at all and so will incur little or none of the 

assurance provision penalties. 
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from the proposal (75 FR 45313). For more details on capacity 

factors for new units, see “Capacity Factors Analysis for New Units 

Final Rule TSD”.

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 in section 

VII.F of this preamble.

Several features of the air quality-assured trading programs 

work in conjunction with the assurance provisions to ensure state 

emissions do not exceed state assurance levels. The air qualityassured trading programs have: state-specific budgets that do not 

include the variability limits and that are the basis for allocating 

allowances in each state so that total allocations in a state cannot 

exceed the state budget; a requirement that owners and operators of 

each source hold enough allowances to cover source emissions for each 

control period; assurance provisions that require owners and 

operators to hold a significant amount of additional allowances in a 

state if the assurance provisions are triggered; and additional 

penalties for failing to hold sufficient allowances under the 

assurance provisions. The underlying mechanism of cap and trade --

with a cap on allowances issued and a requirement to hold allowances 

covering emissions -- has succeeded, even without assurance 

provisions, in broadly reducing emissions below allowance allocation 
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levels. The accumulated data, history, and experience from cap and 

trade programs underscore that emission reduction requirements and 

environmental and public health goals of the programs have been met 

and, in many instances, exceeded. Additionally, EPA has now added 

assurance provisions to ensure that emissions within a state do not 

exceed the state budget with the variability limitation that 

eliminates the state’s significant contribution to nonattainment and 

interference with maintenance in downwind states.

Emissions from a common DR’s group of units in excess of the 

DR’s share of the state budget with the variability limit are not a 

violation of the rule or the CAA, but do lead to strict allowance 

surrender requirements. Specifically, the owners and operators with 

a common DR will be required to surrender two allowances for each ton 

of their proportional share of the exceedance of the state budget 

with the variability limit. Failing to hold sufficient allowances to 

meet the allowance surrender requirement will be a violation of the 

regulations and the CAA and subject to discretionary civil penalties 

under CAA section 113. Allowances surrendered to meet an assurance

provision penalty may be from the year immediately following the 

control period in which the state assurance level was exceeded (i.e., 

the year during which the penalty is assessed) or any prior year. 

Any future vintage allowances beyond the year in which the penalty is 

assessed may not be used to meet an assurance provision penalty.

This penalty level is a change from the proposal, in which one 

allowance was to be surrendered for each ton of emissions over the 
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state assurance level. EPA ran an IPM modeling scenario in order to 

assess the level of penalty that would be sufficient to deter sources 

from exceeding state assurance levels. According to the model, no 

state would exceed its assurance level and incur the two-for-one 

allowance penalty in either 2012 or 2014, although some states emit 

up to the assurance level. The two-for-one allowance surrender 

requirement is significant, and EPA believes that this penalty --

along with the other elements of the Transport Rule discussed above -

- will be sufficient to ensure that the state emissions will not 

exceed the budgets plus the variability limits. See the Assurance 

Penalty Level Analysis Final Rule TSD for further details of the 

analysis.

Below are examples of how the penalty will be assessed for four 

common designated representatives in the same state if the assurance 

provisions are triggered. In the first case, DR1’s combined units 

were allowed to emit up to 71 tons of SO2 (60 * 118 percent), but 

actually emitted 75 tons during the control period, or 4 more than 

their share of the state assurance level. Since the state, as a 

whole exceeded the state assurance level by 15 tons, DR1’s share of 

the penalty is 25 percent of the total penalty, or 8 allowances (25

percent of 30). 
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Figure VII.E-1 Assurance Provision Allowance Surrender Example

Allowances 

Allocated

Allocation 

+ Share of 

Variability

Total 

Emissions

Emissions 

above 

Allocation

Emissions 

above 

Allocation 

+ Share of 

Variability

Share of 

State 

Exceedance

(%)

Penalty 

(Allowances 

Surrendered)

DR1 60 71 75 15 4 25%

 

8 

DR2 20 24 33 13 9 56%

 

17 

DR3 10 12 15 5 3 19%

 

6 

DR4 10 12 10 0 -2 0%

 

- 

TOTAL 100 118 133 33 15 100%

 

30 

DR1, DR2, DR3, and DR4 are all in the same state.

State budget plus 18 percent variability limit is 118 tons (100 + 18 = 118).

State exceeded its assurance level by 15 tons (133 - 118 = 15).

Penalty is 2 allowances per ton over the assurance level (2 x 15 = 30).

Some numbers may not add up due to rounding.
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In the proposal, EPA took comment on whether assurance 

provisions should be implemented starting in 2012 or 2014. While a 

number of commenters supported the proposal to start in 2014, EPA 

received several comments making the case that starting assurance 

provisions in 2012 would be more compatible with the Court’s opinion 

in North Carolina, which emphasized EPA’s obligation to require 

elimination of emissions within the states that significantly 

contribute to nonattainment or interfere with maintenance. In this 

final rule, EPA makes the assurance provisions effective starting in 

2012 because this approach provides even further assurance, 

consistent with North Carolina, that each state’s prohibited 

emissions will be eliminated from the start of the Transport Rule 

trading programs.

F. Penalties

Under the final Transport Rule FIPs (like under the proposed 

rule), the owners and operators of each covered source must hold, as 

of the allowance transfer deadline, an allowance for each ton of SO2

or NOX emitted by the source and are subject to penalties if they fail 

to comply with this allowance-holding requirement.

In particular, the owners and operators must hold in the 

source’s compliance account in the Allowance Management System enough 

allowances issued for the respective Transport Rule annual trading 

program (SO2 Group 1, SO2 Group 2, or annual NOX program) to cover the 

annual emissions of the relevant pollutant from all covered units at 

the source. The allowances must have been issued for the year in 
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which the emissions occurred or a prior year. If the owners and 

operators fail to meet this allowance-holding requirement, they must 

provide -- for deduction by the Administrator from the source’s 

compliance account -- one allowance as an offset, and one allowance 

as an excess emissions penalty, for each ton of emissions (i.e., 

excess emissions) in excess of the amount of allowances held. The 

allowances surrendered for the excess emissions penalty must be 

allocated for the control period in the year immediately following 

the year when the excess emissions occurred or for a control period 

in any prior year. The offset and the excess emissions penalty are 

automatic requirements in that they must be met 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., the control period of one calendar year), constitute a 

violation of the CAA, and the maximum discretionary civil penalty is 

$25,000 (inflation-adjusted to $37,500 for 2010) per violation under 

CAA section 113. This means that, if a source has emissions in 

excess of allowances held for the source as of the allowance transfer 

deadline for a control period, the number of tons of excess emissions 

multiplied by the total number of days in that control period and 

multiplied by $25,000 (inflation adjusted) equals the maximum 

discretionary civil penalty for that occurrence of excess emissions. 

For the ozone-season NOX trading program, the same provisions 

apply as for an annual program, except that the averaging period 
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(i.e., the control period) is the ozone season, not a calendar year. 

Consequently, the relevant emissions are for an ozone season, the 

allowances usable to meet the allowance-holding requirement are 

allowances issued for Transport Rule ozone-season NOX trading program 

for the ozone season involved or a prior ozone season, and the number 

of days used in calculating the maximum civil penalty is the number 

in the ozone season.

Commenters expressed concern that the proposed FIPs expressly 

stated that, for purposes of determining the maximum discretionary 

civil penalty for failure to meet the allowance-holding requirement, 

each ton of emissions lacking a held allowance would be a violation 

and each day in the averaging period involved would be a violation. 

Some commenters compared the proposed penalty provisions for excess 

emissions with the excess emissions penalty provisions under the Acid 

Rain Program and claimed that the proposed penalty provisions 

differed from the Acid Rain Program provisions and were excessive.

In fact, however, the final FIP provisions concerning 

discretionary civil penalties are essentially the same as those under 

the Acid Rain Program, as well as those under the NOX Budget Trading 

Program and the CAIR trading programs. In particular, the Acid Rain 

Program regulations state that each ton of SO2 excess emissions 

constitutes “a separate violation” of the CAA. 40 CFR 72.9(c)(2). 

Moreover, while the Acid Rain Program regulations do not expressly 

address that each day in the averaging period (i.e., a calendar year 

control period under the Acid Rain Program) constitutes a separate 
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violation when a unit has excess emissions for the calendar year, the 

courts have addressed this question. In decisions applying the 

discretionary civil penalty provisions in section 309(d) of the Clean 

Water Act, which are analogous to the civil penalty provisions in CAA 

section 113, the courts have interpreted the provisions to mean that, 

when a source violates the emission limitation for a multi-day 

control period, the source has a violation for each day in the 

control period, as well as for each ton of excess emissions on each 

such day. See, e.g., Chesapeake Bay Foun. V. Gwaltney of Smithfield, 

791 F.2d 304, 313-15 (4th Cir. 1986), Atlantic States Legal Foun. v. 

Tyson Foods, 897 F.2d 1128, 1139-40 (11th Cir. 1990), and U.S. v. 

Allegheny Ludlum Corp., 366 F.3d 164, 169 (3d. Cir. 2004). As noted 

by the courts, the treatment of each ton and each day as a separate 

violation is used for purposes of setting the maximum discretionary 

civil penalty. Because CAA section 113 sets the maximum civil 

penalty, EPA, of course, has the discretion to tailor the penalty 

amount that it seeks in any specific occurrence of excess emissions 

to reflect the circumstances of that excess emission occurrence. See

42 U.S.C. 7413(b)(stating that the Administrator may commence a civil 

action “to assess and recover a civil penalty of not more than 

$25,000 per day for each violation”). Moreover, when a district 

court imposes a civil penalty, the court “retains discretion to 

assess a penalty much smaller than the maximum, as the situation 

requires.” Chesapeake Bay, 791 F.2d at 316. In addition, the Acid 

Rain Program regulations state that any allowance deduction, excess 
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emission penalty, or interest under the Acid Rain Program regulations 

“shall not affect liability” of the owners and operators “for any 

additional fine, penalty, or assessment, or their obligation to 

comply with any other remedy, for the same violation, as ordered 

under the [CAA]”, including under CAA section 113 providing for 

discretionary civil penalties. 40 CFR 77.1(b). In summary, under 

the Acid Rain Program, each ton of excess emissions and each day in 

the averaging period (i.e., the calendar year) constitute a 

violation, the resulting number of violations times $2,000 is the 

maximum civil penalty for violating owners and operators, and EPA has 

the discretion to impose a civil penalty at or below such maximum, in 

addition to the automatic requirement to surrender one allowance and 

pay $2,000 (inflation adjusted) for each ton of excess emissions.

The final FIPs take an analogous approach to that under the Acid 

Rain Program. Specifically, the final FIPs state both that each ton 

of excess emissions is a violation of the CAA and that each day in 

the averaging period (i.e., a calendar year under the annual programs 

and the ozone season under the ozone-season program) is a violation. 

Moreover, the imposition of civil penalties at or below the maximum 

amount resulting from the maximum penalty calculation is in addition 

to the automatic allowance surrender and penalty totaling 2 

allowances per ton of excess emissions. Thus, commenters’ assertion 

that the approach in the final FIPs is inconsistent with the approach 

in the Acid Rain Program is incorrect. Moreover, EPA has taken this 

same general approach in two other trading programs (i.e., the NOX
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Budget Trading Program and the CAIR trading programs), whose 

regulations explicitly state that each ton and each day of the 

averaging period constitute a violation. See 40 CFR 96.54(d)(3) (NOX

Budget Trading Program); and 40 CFR 96.106(d)(CAIR).

In any event, EPA maintains that the approach of treating each 

excess emission ton and each day in the averaging period as a 

violation for purposes of calculating the maximum discretionary civil 

penalty is reasonable. Some commenters suggested that only the days 

on which a source’s cumulative control period emissions exceed the 

amount of allowances that the source then holds for that control 

period should be treated as a violation. However, this suggested 

approach makes little sense in the context of the Transport Rule 

trading programs.

In order to provide owners and operators compliance flexibility, 

the Transport Rule trading programs do not require source owners and 

operators to hold any amount of allowances to cover emissions until 

the allowance transfer deadline, no matter what the source’s 

cumulative control period emissions are before that deadline. The 

commenters’ approach of comparing -- each day, cumulative emissions 

and allowances held -- for purposes of calculating maximum civil 

penalties would be inconsistent with the flexibility that EPA intends 

to provide owners and operators. For example, under the commenters’ 

suggested approach, owners and operators that buy or sell allowances 

in the allowance market or hold allowances in a company-wide account, 

do not transfer allowances into their source’s compliance account 
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until just before the allowance transfer deadline, and end up with 

some excess emissions for the calendar year would face a 

significantly higher maximum civil penalty than owners and operators

that every day increase the amount of allowances held in their 

source’s compliance account as the source’s cumulative emissions 

increase and end up with the same amount of excess emissions for the 

calendar year. In short, the commenters’ approach would penalize 

owners and operators that use some of the compliance flexibility that 

the trading programs are intended to provide.

EPA also maintains that it is reasonable to both impose the 

automatic allowance surrender and penalty provisions and to retain 

the discretion to impose civil penalties for the same occurrence of 

excess emissions. This approach encourages compliance with the 

allowance-holding requirement by ensuring that violating owners and 

operators are penalized automatically (i.e., without any further 

administrative or judicial proceedings, except for appeals) and that 

EPA can seek additional penalties where the circumstances warrant 

discretionary civil penalties. In fact, the Acid Rain Program, for 

which CAA Title IV mandated this approach, has achieved a very high 

level of compliance with the requirement to hold allowances covering 

SO2 emissions and therefore resulted in major reductions in utility 

SO2 emissions. See 42 U.S.C.7651j(a). Similarly, the NOX Budget 

Trading Program and CAIR trading programs, which took the same 

approach, also have achieved very high compliance levels and major 

utility emission reductions.
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EPA notes that, in calculating maximum civil penalties when owners 

and operators fail to hold allowances required under the assurance 

provisions in the final FIPs, EPA takes a similar approach in 

determining the number of violations. Each ton for which an 

allowance is not held as required and each day in the control period 

involved constitute a violation of the CAA. As discussed elsewhere 

in this preamble, EPA believes that this calculation approach is also 

reasonable in the context of the assurance provisions and that taking 

an approach like the commenters’ suggested approach described above 

would be inconsistent with some of the flexibility that the Transport 

Rule trading programs are intended to provide.

G. Allowance Management System

The final Transport Rule trading programs, like the proposed 

preferred remedy, utilize EPA’s allowance management system (AMS), 

which currently supports allowance surrender, transfer, and tracking 

activity under the Acid Rain Program and CAIR. EPA received no 

adverse comment on this aspect of the proposed rule.

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-related provisions 

of the Transport Rule trading programs. As was proposed, each of the 

final SO2 trading programs and final NOX trading programs is 

separately handled in the AMS, which is 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. 
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In addition, the AMS tracks: the allocation of all SO2 and NOX

allowances; holdings of SO2 and NOX allowances in compliance accounts 

(i.e., accounts for individual covered sources), general accounts 

(i.e., accounts for other entities such as companies and brokers), 

and assurance accounts (i.e., accounts for allowance surrender by 

owners and operators of groups of sources and units with common 

designated representatives under the assurance provisions); deduction 

of SO2 and NOX allowances for compliance purposes (including 

deductions from assurance accounts where necessary); and transfers of 

allowances between accounts. The AMS also allows the public to see 

whether each source is in compliance and provides information to the 

allowance market and the public in general, including information on

ownership of allowances, dates of allowance transfers, buyer and 

seller information, and the serial numbers of allowances transferred.

H. Emissions Monitoring and Reporting

Under the proposed rule, units subject to the Transport Rule 

trading programs would monitor and report NOX and SO2 mass emissions 

in accordance with 40 CFR part 75, as incorporated in the proposed 

rule, and with certain other specified requirements, such as 

compliance deadlines.

In the final rule, like the proposed rule, covered units must 

comply with emissions monitoring and reporting requirements that are 

largely incorporated from Part 75 monitoring and reporting 

requirements. 
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Under the final rule and 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, the 

Administrator can approve petitions for alternatives to Transport 

Rule and Part 75 monitoring, recordkeeping, and reporting 

requirements. 

Further, the final rule and Part 75 specify 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 24-hour calibrations. In addition, when a 

monitoring system is not operating properly, standard substitute data 

procedures are applied and result in a conservative estimate of 

emissions for the period involved. 

In addition, the final rule and Part 75 require electronic 

submission, to the Administrator and in a format prescribed by the 

Administrator, of a quarterly emissions report. The report must 

contain all of the data required concerning NOX annual and ozoneseason and SO2 annual emissions. 

Most Transport Rule units are in states subject to CAIR and are 

already monitoring and reporting NOX and/or SO2 under CAIR and the 

Acid Rain Program, which programs also use Part 75 monitoring and 
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reporting. Units under the Transport Rule annual trading programs 

and in states subject to CAIR generally have no changes to their 

monitoring and reporting requirements. These units must continue to 

monitor and submit reports on a year-round basis as they have under 

CAIR. Therefore, units in the following states must monitor and 

report both SO2 and NOX year-round under the Transport Rule: Alabama, 

Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, 

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

Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 

Virginia, West Virginia and Wisconsin.

Some states (Kansas, Minnesota, and Nebraska) subject to the 

Transport Rule annual trading programs were not subject to CAIR. 

Transport Rule units in those states must meet monitoring and 

reporting requirements that are new except to the extent the units 

were subject to Part 75 under some other program (such as the Acid 

Rain Program). 

Further, some states (Florida, Louisiana, and Mississippi) 

subject to the Transport Rule ozone-season trading program but not 

the Transport Rule annual trading programs were subject to the annual 

and ozone-season trading programs under CAIR. Transport Rule units 

in those states must continue to monitor and report in accordance 

with Part 75 but have the option of monitoring and reporting on a 

year-round or ozone-season-only basis.

In addition, one state (Arkansas) subject to the Transport Rule 

ozone-season trading program but not to the Transport Rule annual 
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trading program was similarly subject to only the ozone-season 

trading program in CAIR. Transport Rule units in that state continue 

to have the option of monitoring and reporting NOX on a year-round or 

ozone-season-only basis. 

Finally, some states (Connecticut, Delaware, District of 

Columbia, and Massachusetts) that were subject to CAIR are not 

subject to the Transport Rule. Electric generating units in those 

states must continue to meet monitoring and reporting requirements 

only to the extent the units are subject to Part 75 under some other 

program (such as the Acid Rain Program or a state adopted program 

requiring such monitoring and reporting). 

EPA is finalizing requirements for existing Transport Rule units 

in states covered by the Transport Rule annual trading programs to 

monitor and report SO2 and NOX emissions by January 1, 2012 programs 

and for existing Transport Rule units in states covered by the 

Transport Rule ozone-season trading program to monitor NOX emissions 

by May 1, 2012. The use of Part 75 certified monitoring 

methodologies is required in both cases. As discussed previously, 

most covered existing units will generally have no changes to their 

monitoring and reporting requirements and will continue to monitor 

and submit reports under Part 75 as they have under CAIR. Existing 

units that have not been subject to Part 75 monitoring and reporting 

requirements in the past have less than 1 year to install, certify, 

and operate the required monitoring systems. EPA believes that these 

units will be able to comply with this requirement because the 
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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 EPA believes that there is sufficient time to 

accomplish this by the deadline for existing units in the final rule.

In the proposed rule, the compliance deadline for installing, 

certifying, and operating the required monitoring systems at new 

units was based upon the date of commencement of commercial 

operation. A new unit would have to install and certify its 

monitoring system within 180 days of the commencement of commercial 

operation. The final rule adopts this deadline, which is consistent 

with the approach recently adopted in Part 75 under the Acid Rain 

Program. See 76 FR 17288, 17289 (March 28, 2011)). 

Using this deadline (rather than a deadline, used previously in 

Part 75, of the earlier of the unit’s 90th operating day or 180 days 

after the unit’s commencement of commercial operation) ensures that 

new units have sufficient time to complete installation and 

certification of monitoring systems and facilitates units’ 

compliance. Because of unit shakedown problems, some new units have 

had difficulty meeting a deadline earlier than 180 days after 

commencement of commercial operation. Further, using this deadline 

facilitates owners’ and operators, and EPA’s, ability to track 

important dates related to monitoring, reporting, and allowance 

holding. Under the final rule, the requirement that a unit hold 

enough allowances to cover its emissions starts on the later of the 
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commencement of the Transport Rule trading program involved or the 

deadline for installation and certification of the monitoring system. 

Having a simple, easily determined deadline (180 days after the 

commencement of commercial operation) makes it easier for owners and 

operators and EPA to determine when allowance-holding requirements 

begin, as well as when monitoring and reporting requirements begin. 

In contrast, using a deadline involving determination of a unit’s 

90th operating day required keeping track of any days on which the 

unit did not operate (e.g., due to problems associated with shakedown 

of the unit). EPA found that owners and operators have had more 

difficulty reporting the 90th operating day than in reporting the 

commencement of commercial operation, and once the latter date is 

reported, EPA can independently determine the 180th calendar day 

after the reported date.

I. Permitting

1. Title V Permitting

The final Transport Rule (like the proposed rule) does 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.

84 All major stationary sources of air pollution and 

certain other sources are required to apply for title V operating 

permits that include emission limitations and other conditions as 

necessary to assure compliance with applicable requirements of the 

 

84 Part 70 addresses requirements for state Title V programs, and Part 

71 governs the federal Title V program.
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CAA, including the requirements of the applicable State 

Implementation Plan. CAA §§ 502(a) and 504(a), 42 U.S.C. §§ 7661a(a) 

and 7661c(a). The “applicable requirements,” that must be addressed 

in title V permits are 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 final Transport Rule, most of the sources at which they are 

located are already or will be subject to Title V permitting 

requirements. For sources subject to Title V, the requirements 

applicable to them under the final FIPs will be "applicable 

requirements" under Title V and therefore will need to be addressed 

in the Title V permits. For example, requirements under the final 

FIPs concerning designated representatives, monitoring, reporting, 

and recordkeeping, the requirement to hold allowances covering 

emissions, the assurance provisions, and liability will be 

“applicable requirements” to be addressed in the permits. 

The Title V permits program includes, among other things, 

provisions for permit applications, permit content, and permit 

revisions that will address the applicable requirements under the 

final FIPs in a manner that will provide the flexibility necessary to 

implement market-based programs such as the Transport Rule trading 

programs. 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 
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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). Consistent with this provision in the Title V 

regulations, the Transport Rule trading program regulations 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 will also be 

included in each Title V permit for a covered source. As a result, 

allowances can be traded (or allocated, held, or deducted) under the 

final 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 final FIPs set forth in detail, and 

reference relevant provisions in Part 75 concerning, the approaches 

that are available for covered units to use for monitoring and 

reporting emissions (i.e., approaches using a continuous emission 

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 
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subpart E of Part 75). The final FIPs also require unit owners and 

operators to submit monitoring system certification applications (or, 

for alternative monitoring systems, petitions) to EPA establishing 

the monitoring and reporting approach actually to be used by the unit 

and allow owners and operators to submit petitions for alternatives 

to any specific monitoring and reporting requirement. These 

applications and petitions are subject to EPA review and approval to 

ensure consistency in monitoring and reporting among all trading 

program participants, and EPA’s responses to any petitions for 

alternative monitoring systems or for alternatives to specific 

monitoring or reporting requirements are to be posted on EPA’s 

website. Moreover, EPA intends that each covered unit’s Title V 

permit will include a description of the general approach that the 

covered unit is required to use for monitoring and reporting 

emissions and that the description will reference the relevant 

sections of the Transport Rule trading program regulations and Part 

75 and will state that the requirements may be modified through EPA 

approval of petitions for alternatives to specific requirements. 

Finally, consistent with §§70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of 

the Title V regulations, the final FIPs provide that a description of 

the general monitoring and reporting approach for a covered unit can 

be added to, or an existing description of a unit’s general 

monitoring and reporting approach can be changed, in a Title V 

permit, using minor permit modification procedures, provided that the 

approach being described in the changed or new general description 
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and the requirements applicable to that approach are already 

incorporated elsewhere in the permit. As a result, minor permit 

modification procedures can be used to revise a covered unit’s Title 

V permit to be consistent with the monitoring and reporting approach, 

or any changes in the approach, allowed for the unit by EPA through 

the monitoring system certification or petition process under the 

Transport Rule trading programs. 

As new applicable requirements under Title V, the requirements 

for covered units under the final FIPs will 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)).

85 In contrast to the approach in CAIR of imposing 

permitting requirements and deadlines independent of those under 

Title V, the approach to permitting under the final FIPS of imposing 

no independent permitting requirements should reduce the burden on 

sources already required to be permitted under Title V and on 

permitting authorities. For sources newly subject to Title V that 

will also be covered sources under the final FIPs, the initial Title 

V permit issued pursuant to 40 CFR 70.7(a) will address the final FIP 

requirements. 

 

85 A permit is reopened for cause if any new applicable requirements 

(such as those under a FIP) become applicable to a covered source 

with a remaining permit term of 3 or more years. If the remaining 

permit term is less than 3 years, such new applicable requirements 

will be added to the permit during permit renewal. See 40 CFR 

70.7(f)(1)(i) and 71.7(f)(1)(i).
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In order to ensure that covered sources’ Title V permit 

provisions concerning the final FIPs will reflect the Transport Rule 

trading program requirements and flexibilities properly and in a 

manner consistent from permit to permit, EPA intends to issue 

guidance to assist permitting authorities. This guidance would 

include information on permit issuance and permit modification 

requirements, as well as a permit content template that will identify 

the applicable requirements under the applicable Transport Rule 

trading program and thereby ensure that they will be correctly and 

comprehensively reflected in each permit in a manner that will reduce 

the burden on sources and permitting authorities related to the 

issuance of the permit and will reduce the need for permit revisions.

2. New Source Review

a. Background

EPA recognizes that, following the vacatur of the new source 

review (NSR) pollution control project exemption in New York v. EPA, 

413 F.3d 3, 40-41 (D.C. Cir. 2005), pollution control projects, 

including pollution control projects constructed to comply with this 

rule, have the potential to trigger NSR permitting. 

This issue was previously addressed in the context of CAIR. On 

December 20, 2005, the EPA agreed to reconsider one specific aspect 

of CAIR. In that notice, EPA granted reconsideration and sought 

comment on the potential impact of the opinion in New York v. EPA, 

which vacated the previously existing NSR exemption for certain 

environmentally beneficial pollution control projects. For this 
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reconsideration, EPA conducted an analysis which showed that the 

court decision did not impact the CAIR analyses. Details of this 

analysis can be found in a technical support document which is 

available on EPA’s website at: http://epa.gov/cair/pdfs/0053-

2263.pdf

Because GHG emissions were not considered by EPA to be air 

pollutants within the meaning of the CAA at the time of CAIR, GHG 

emissions were not addressed in 2005 analysis. GHG requirements 

related to the component of NSR concerning the Prevention of 

Significant Deterioration (“PSD”) program are 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, 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 exceed the thresholds in 

the Tailoring Rule. 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 
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increase by at least 75,00086 tons per year of CO2 equivalent (CO2e). 

b. Proposed rule

In the proposed rule, EPA presented the following conclusions:

(1) the 2005 analysis remains current and relevant for all 

pollutants except for GHG, and it shows that NSR 

requirements would not significantly impact the 

construction of controls that are installed to comply with 

the proposed Transport Rule. 

(2) it is very unlikely that pollution control projects 

would cause GHG increases that would exceed the 75,000 tons 

per year threshold.

Consistent with these proposed conclusions, EPA also concluded 

that there would be no significant impacts from NSR for any pollution 

control projects resulting from the proposed rule such as low-NOX

burners, SO2 scrubbers, or SCR. EPA requested comment on this issue.

c. Public Comments. 

EPA received a number of comments on the NSR issue, which can be 

divided into four types of comments: (1) comments related to GHGs, 

 

86 We note that, for sources that are modifying and are not subject to 

PSD for emissions of a non-GHG pollutant, in order to be subject to 

PSD for GHGs the source must not only have an emissions increase of 

75,000 TPY CO2e, but must also have a PTE of at least 100,000 TPY CO2e 

and 100 TPY mass GHG. See 40 CFR 52.21(b)(49)(v)(b). However, since 

it is reasonable to assume that all sources that are potentially 

subject to the Transport Rule will have a PTE of at least 100,000 TPY 

CO2e and 100 TPY, for the purposes of discussions in this section we 

will only note the requirement to have an emissions increase of 

75,000 TPY CO2e.
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(2) comments related to sulfuric acid mist, (3) comments related to 

CO emission increases from low-NOX burners, and (4) suggested changes 

to the EPA rules.

Greenhouse gases. A number of commenters recommended that EPA 

should document and substantiate its conclusion that greenhouse gases 

would be unlikely to trigger NSR requirements. Other commenters 

suggested that some units installing a FGD scrubber could exceed the 

75,000 ton threshold for GHGs in the Tailoring Rule by emitting CO2

produced from the chemical reaction of SO2 with limestone. 

Commenters also suggested that NSR applicability for GHGs would also 

need to consider that an FGD would consume 1-3 percent of a scrubbed 

unit’s generation, referred to as “parasitic load,” which (all else 

held equal) lowers that unit’s net generation.87 Commenters argued 

that any post-retrofit increase in generation to offset that 

“parasitic load” could lead to GHG increases potentially exceeding 

the 75,000 ton threshold.

Sulfuric Acid Mist. Two commenters noted that use of high 

sulfur fuels, in combination with SCR, can lead to increases in 

sulfuric acid mist, a pollutant regulated under NSR. One of these 

commenters noted that reagent injection was necessary to avoid 

triggering NSR for sulfuric acid mist when their SCR was installed.

 

87 “Net generation” refers to total generation minus the amount of 

power consumed on-site for various purposes, including operation of 

pollution control equipment.
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Carbon monoxide (CO). One commenter believed that EPA’s 2005 

analysis may not be adequate as it related to carbon monoxide 

emission increases that result from installation of low-NOX burners. 

The commenter noted EPA’s statement in the 2005 analysis that read as 

follows: “Since the NOX removal efficiencies used in EPA’s analysis 

are not aggressive, it is believed that the units installing 

combustion controls can opt for moderate levels of overfire air flow 

rates and still achieve the NOX reduction levels projected in EPA’s 

analysis, without causing significant increases in the CO and 

unburned carbon emissions.” The commenter suggested that the 

transport rule NOX may be more aggressive than CAIR and thus EPA 

should conduct a review to determine whether EPA retains the same 

conclusion regarding CO emissions.

Recommended Rule Changes. Some commenters suggested changes to 

EPA rules to address their concerns that control equipment installed 

as a result of the Transport Rule could trigger NSR. Some commenters 

suggested that EPA craft an exclusion from NSR in the Transport Rule. 

One of these commenters suggested that EPA could do this by: (1) 

providing special definition of baseline actual emissions; (2) a 

causation determination specifically tied to the Transport Rule; or 

(3) interpret the term “stationary source” in CAA 110(a)(4) in a way 

that doesn’t impede Transport Rule compliance. 

Other commenters expressed the concern that if NSR is triggered, 

the proposed Transport Rule did not allow enough time for compliance 

for sources needing to install control equipment. These commenters 
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recommend that EPA should waive Transport Rule requirements or 

provide extra allowances until NSR review is complete.

d. Final rule and responses to comments. 

Greenhouse Gases. EPA has carefully reviewed relevant data in 

assessing the comments suggesting that NSR permitting would likely be 

triggered for facilities installing FGD scrubbers to comply with this 

rule. EPA believes that sources installing FGD to comply with the 

Transport Rule can achieve those installations without triggering 

NSR.

EPA notes that its forecast of the number and extent of FGD 

scrubber installations substantially decreased since the time of 

proposal. For the proposed rule, EPA modeled 14 GW of FGD retrofit 

installations by 2014. For the final rule, EPA models a total of 5.7 

GW of wet FGD installations from 7 units at 5 plants.

There are two factors associated with wet FGD scrubbers that 

commenters suggested individually or in combination could lead to 

increases above the 75,000 tons per year threshold in the Tailoring 

Rule. The first is the CO2 chemically produced from the reaction of 

SO2 with limestone in wet FGD scrubbers. The second is that owners or 

operators of the affected units may desire to increase coal usage 

after the retrofit is made to offset the “parasitic load” that is 

consumed on-site in order to operate the scrubber. 

With respect to chemically produced CO2, EPA concludes that only

in very limited circumstances when installation of a scrubber is 

coupled with a change to considerably higher sulfur coal could 
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installation of a wet limestone scrubber be associated with a more 

than 75,000 ton increase in CO2 emissions. EPA finds this possibility 

unlikely to occur. For example, EPA’s acid rain emissions reporting 

system shows that the plant with the greatest emissions from 

unscrubbed units in 2009 emitted about 103,000 tons of SO2 from those 

units. If this plant installed a wet limestone scrubber assumed to 

reduce those SO2 emissions by 96 percent, EPA calculates that 

chemically produced CO2 could increase emissions by:

 103,000 X (0.96) X (44/64) = 67,980 tons CO2.

88

Therefore, EPA finds that all currently uncontrolled units are 

technically capable of retrofitting with wet FGD without chemically 

produced CO2 increases leading to a triggering of NSR. In limited 

circumstances, an owner or operator may elect to switch fuels to a 

significantly higher-sulfur coal subsequent to FGD installation and 

may risk an increase in chemically produced CO2 emissions that would

trigger NSR, but such a decision is not necessary in order to 

successfully install and operate the scrubber as a strategy for 

compliance with Transport Rule requirements.

With respect to the “parasitic load” issue, EPA estimates that 

today’s wet FGD retrofit technology would consume typically about 1.7 

 

88 The factor 44/64 reflects the relative molecular weight of CO2 and 

SO2, respectively. A wet FGD’s removal of one ton of SO2 involves a 

chemical reaction that releases the equivalent molecular weight of CO2

(thus equaling 44/64 of a ton of CO2 emissions).
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percent of on-site generation.89 If a facility made no other changes 

to its operation other than installing an FGD retrofit, that 

facility’s CO2 emissions from fuel combustion would remain constant. 

It is possible, however, that a source’s owner or operator may elect 

to increase coal usage by some amount after retrofitting FGD, if for 

example the owner or operator desires to increase net generation 

after retrofitting. Under NSR, any such source would be able to 

compare such a CO2 emissions increase against the highest average 

annual emissions in any consecutive 24-month period from a 5-year 

historic baseline. Therefore, a unit retrofitting a scrubber under 

the Transport Rule may be able to increase its CO2 emissions by more 

than 75,000 tons without triggering NSR if that increase would 

register as less than 75,000 tons against a higher emissions level in 

the aforementioned NSR baseline. 

EPA also notes that scrubber installations provide facilities 

with the opportunity to make other capital improvements at the unit 

on which the scrubber is installed to improve the efficiency of 

boilers, steam turbines, motors, other auxiliary equipment, and plant 

control systems. Such improvements could allow a retrofitting unit

to lower its CO2 output rate such that a subsequent decision to 

increase net generation may not result in increased coal use, or may 

limit any CO2 emission increase to less than the 75,000 tons per year 

threshold for triggering NSR.

 

89 Documentation Supplement for EPA Base Case v.4.10_FTransport –

Updates for Final Transport Rule.
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As discussed in section VII.C, EPA notes that the Transport Rule 

does not mandate any specific control activity, including scrubber 

retrofitting, as a compliance strategy for units within a state to 

meet that state’s SO2 budget. As demonstrated by EPA’s “no FGD” 

sensitivity analysis described in VII.C, covered sources within the 

Group 1 states are capable of meeting their emission reduction 

obligations through a variety of emission reduction strategies even 

if no unit is able to complete a scrubber installation by 2014. 

Therefore, EPA does not believe that NSR permitting presents an 

obstacle in any way to Transport Rule compliance, even if a given 

unit retrofitting with FGD triggers NSR for CO2. 

For some plants, EPA’s IPM modeling forecasts installation and 

operation of dry sorbent injection (DSI) systems. EPA does not 

believe any of these systems would result in CO2 emission increases 

above the 75,000 ton threshold. Moreover, given the relatively short 

construction schedule for DSI systems, EPA believes that if any of 

the plants did require NSR permitting, installation of DSI could 

still be accomplished by 2014.

In summary, EPA believes that the operators of plants projected 

to install scrubbers for Transport Rule SO2 reductions could readily 

develop workable compliance strategies whether or not such an 

installation would trigger NSR. Plant owners could readily develop 

strategies to avoid emission increases that would trigger NSR, 

including but not limited to alternative SO2 reduction strategies or 

technologies, efficiency improvements, or the ability to adjust net 
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electricity generation to prevent a 75,000 ton increase in CO2

emissions. EPA believes that projected scrubber installations under 

the Transport Rule are broadly unlikely to trigger NSR, but even in 

the limited conditions where such a triggering may occur, the NSR 

permitting process would not infringe on a state’s ability to comply 

with its budgets under the Transport Rule. (See section VII.C for 

more details on EPA’s analysis of a “no FGD” sensitivity supporting 

these points.)

Sulfuric Acid Mist. EPA continues to conclude that, consistent 

with the 2005 TSD, sulfuric acid mist increases due to compliance 

with this rule are very unlikely to trigger NSR permitting. Such 

increases are most commonly seen from installation of SCR units on 

facilities with relatively high sulfur coal. However, as 

acknowledged by one of the commenters, engineering solutions have 

been developed to prevent such increases, and EPA believes that 

facility owners would take this into account in designing such an SCR 

system. Moreover, EPA’s IPM modeling of the NOX budgets in the final 

rule suggests that no new SCR units will result from the final rule.

Carbon monoxide. EPA concludes that any NSR permitting required 

due to CO increases associated with NOX controls should not hinder the 

ability of sources to comply with Transport Rule requirements. For 

states that were included in the CAIR for either ozone, PM2.5, or 

both, EPA finds no evidence to suggest that the NOX control 

requirements of the Transport Rule would require more aggressive 

controls triggering NSR. As EPA’s baseline analysis acknowledges, 
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many sources in these states installed NOX controls to comply with 

CAIR. In addition, their historic emissions reflect operation of 

these controls and there is no evidence to suggest that the Transport 

Rule will require sources to operate these controls more 

aggressively, thereby increasing CO emissions above the relevant 

threshold and triggering NSR. In a few states that were not covered 

by CAIR, a limited number of facilities may install new combustion 

controls (such as low-NOX burners, overfire air, or other combustion 

controls or upgrades) as a result of the Transport Rule. EPA 

expects relatively few such installations, and believes that NSR 

permitting, if required, is not an obstacle to compliance with the 

rule. First, EPA believes that NSR permitting should be relatively 

straightforward for these installations and that the BACT 

determination for CO will be very straightforward. EPA expects a 

relatively short time period for permitting, and as discussed later, 

EPA is planning to initiate actions that will further expedite any 

required permitting.

Second, EPA notes that the rule achieves reductions through a 

trading program rather than direct control requirements. 

Accordingly, even if a few installations do not have controls in 

place at the very beginning of the compliance period, this should not 

hinder the ability of states to meet their ozone-season NOX budgets. 

Covered sources have a suite of NOX pollution control strategies and 

technologies available to them, including coal selection, selective 

non-catalytic reduction, gas re-burn, low-NOX burner and overfire air 
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installations or upgrades, and neural network optimization of 

combustion controls operation. Sources may consider all of these 

technologies and strategies, which can be designed and operated so as 

to minimize CO emission increases that may otherwise trigger NSR. 

EPA also notes that during the downtime for installation of the 

construction controls, there would be no NOX emissions, and thus the 

source’s allowance holding requirements would also be lower for that 

period.

Recommended Rule Changes. EPA disagrees with commenters who 

suggested rule changes, either to the NSR program or to this rule, to 

account for installations triggering NSR. As noted above, EPA 

concludes that NSR would be triggered at most for just a few of the 

projected control installations. EPA believes, however, that even if 

required these NSR permits would likely be issued in a timely manner 

given the overall environmental benefits resulting from the control 

equipment installation. In addition, this rule’s requirements are 

based on a flexible trading approach rather than a direct control 

approach. Accordingly, if this affect occurs for only a few 

installations, EPA believes that any extra emissions that occur 

during the relatively short time needed to obtain an NSR permit could 

be accommodated within the overall trading system.

Expediting Permitting. In the limited circumstances where 

pollution control installations under the Transport Rule may trigger 

NSR, we also note that an expedited permitting process can occur with 

sufficient time to obtain permits and achieve emission reductions 
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under the Transport Rule programs. For this reason, we strongly 

encourage permitting authorities to expedite permitting for any such 

projects, which are likely to be very limited in number. To ensure 

that the permitting decisions are expedited, separate from this 

rulemaking EPA will provide assistance and guidance in order to 

expedite issuance of any such permits. For example, we are considering 

assistance that would serve to expedite BACT reviews or required air 

quality analysis. EPA requests early notification of any specific 

cases where such guidance and assistance may be needed.

J. How the Program Structure is Consistent with Judicial Opinions 

Interpreting the Clean Air Act

The air quality-assured trading programs established by this 

rule eliminate all of the emissions that EPA has identified as 

significantly contributing to downwind nonattainment or interference 

with maintenance90 in a manner that is consistent with section 

110(a)(2)(D)(i) of the CAA as interpreted by the D.C. Circuit in 

 

90 As explained in greater detail in Section VI of this notice, for 

each covered state, EPA has identified emissions that must be 

prohibited pursuant to section 110(a)(2)(D)(i)(I). In most 

instances, EPA has determined that elimination of such emissions is 

sufficient to satisfy the requirements of that section. Thus, in 

these instances, the budgets represent an estimate of the emissions 

that will remain after the elimination of all emissions in that state 

that significantly contribute to nonattainment or interfere with 

maintenance of the NAAQS in another state. In a few limited 

instances, however, EPA determined that elimination of the emissions 

is necessary but may not be sufficient to satisfy the requirements of 

that section. In these instances, the budgets represent an estimate 

of the emissions that will remain after the elimination of all 

emissions that EPA, at this time, has determined must be eliminated.
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North Carolina, 531 F.3d 896. The FIPs finalized in this action 

require sources to participate in air quality-assured interstate 

emission trading programs that 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 emission allowances sufficient to cover their emissions, 

effectuate the requirement that emission reductions occur within the 

state. See 42 U.S.C. 7410(a)(1)(2)(D).

The state budgets developed in this rule represent an estimate 

of the emissions that will remain in a given state after the 

elimination of all emissions in that state that EPA has determined 

must be prohibited pursuant to section 110(a)(2)(D)(i)(I). However, 

for the reasons explained above, the amount of emissions that remain 

after the requirements of 110(a)(2)(D)(i)(I) are satisfied may vary. 

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 a state’s significant contribution to 

nonattainment or interference with maintenance is defined by EPA as 

all emissions that can be eliminated for a specific cost (as 

explained above, using air quality considerations to identify this 

cost threshold), and because EGU baseline emissions are variable, the 

amount of emissions remaining in a state after all significant 

contribution or interference with maintenance is eliminated is also 
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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 to nonattainment or 

interference with maintenance could exceed the state budget without 

variability.

For this reason, EPA determined that it is appropriate for the 

program to recognize the inherent variability in state EGU emissions. 

The program does so by identifying a variability range for each state 

in the program. The assurance provisions in the program, in turn, 

limit a state’s emissions to the state’s budget with variability 

limit. 

In addition, the requirement that all sources hold emission 

allowances sufficient to cover their emissions (and the fact that the 

total number of emission 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 or interference with maintenance) 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 
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multiple states, factors that affect electricity generation, and thus 

EGU emission levels, are more likely to vary significantly within the 

region so that resulting emission 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 use of state budgets with 

variability limits may allow limited shifting of emissions between 

states is not inconsistent with the court’s holding that emission 

reductions must occur “within the state.” North Carolina, 531 F.3d 

at 907. Under the FIPs, no state may emit more than its budget with 
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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 to 

nonattainment or interference with maintenance. It is thus 

consistent with the statutory mandate of section 110(a)(2)(D)(i)(I) 

as interpreted by the Court. 

Most commenters voiced support for a remedy option that allows 

some degree of interstate trading. However, one commenter argued 

that the structure of the preferred trading remedy that EPA proposed 

is legally problematic. The program, the commenter argues, provides 

no legal assurance that the variability margins will be used by 

market participants to account for variability. The commenter does 

not suggest a solution, but instead says, if a solution cannot be 

found, EPA should not allow any amount of interstate trading. 

EPA disagrees with the commenter that the structure of the 

preferred interstate trading program is legally problematic. In 

North Carolina, the Court held that the CAIR interstate trading 

programs were inconsistent with section 110(a)(2)(D)(i)(I), 

concluding that “EPA’s apportionment decisions have nothing to do 

with each state’s ‘significant contribution’” (531 F.3d at 907) 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 
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other State.’” (531 F.3d at 908). It emphasized that “[t]he trading 

program is unlawful, because it does not connect states’ emission 

reductions to any measure of their own significant contributions. To 

the contrary, it relates their SO2 reductions to their Title IV 

allowances . . . . The allocation of NOX caps is similarly arbitrary 

because EPA distributed allowances simply in the interest of 

fairness.” 531 F.3d at 930. As explained in this rule, EPA has 

addressed these concerns by using source specific analysis to 

identify each individual state’s significant contribution to 

nonattainment and interference with maintenance, and including 

assurance provisions to ensure that the necessary reductions occur in 

each state. The Court did not go further to prohibit all interstate 

trading. In fact, it notes that “after rebuilding, a somewhat 

similar CAIR may emerge” (531 F.3d at 930). For all of these 

reasons, EPA does not believe the opinion in North Carolina can be 

read to stand for the proposition that no interstate trading can be 

allowed unless the specific reasons behind market participants’ 

decisions to purchase allowances can be ascertained. Because 

allowance purchase decisions are likely to be based on multiple 

factors, which can include the desire to hedge against potential 

emission variability as well as to address actually occurring 

variability, requiring ascertainment of the specific reasons for 

allowance purchases would be tantamount to prohibiting all interstate 

trading. 
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Moreover, as discussed above, variability is inherent to the 

operation of the electric generation system and thus to emissions 

from this sector. In fact, variability in emissions occurs every 

year in every state and, like variability of year-to-year weather 

conditions (which is a major cause of emission variability), cannot 

be accurately predicted. See the Power Sector Variability Final Rule 

TSD in the docket for this rulemaking. EPA maintains that its 

approach of allowing state EGU emissions each year to vary by up to 

the historically representative, annual amount of inherent, emission 

variability reasonably reflects the realities of the electric 

generation system and is consistent with the North Carolina decision. 

In summary, the variability limits take into account inherent 

variability over time of emissions in each state from this sector 

while also ensuring that each state makes necessary emission 

reductions to eliminate significant contribution and interference 

with maintenance. EPA thus concludes that the commenter’s argument 

that the use of variability limits allows sources “within the state” 

to avoid eliminating their significant contribution or interference 

with maintenance is without merit.

VIII. Economic Impacts of the Transport Rule

A. Emission Reductions

The projected impacts of this final rule as presented throughout 

the preamble do not reflect minor technical corrections to SO2 budgets 

in three states (KY, MI, and NY) made after the impact analyses were 
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conducted. These projections also assumed preliminary variability 

limits that were smaller than the variability limits finalized in 

this rule. EPA conducted sensitivity analysis confirming that these 

differences do not meaningfully alter any of the Agency’s findings or 

conclusions based on the projected cost, benefit, and air quality 

impacts presented for the final Transport Rule. The results of this 

sensitivity analysis are presented in Appendix F in the final 

Transport Rule RIA.

Table VIII.A-1 presents projected power sector emissions in the 

base case (i.e., without the Transport Rule or CAIR) compared to 

projected emissions with the Transport Rule in 2012 and 2014 for all 

covered states. Table VIII.A-2 presents 2005 historical power sector 

emissions compared to projected emissions with the Transport Rule in 

2012 and 2014. Note that for ozone-season emissions, these tables 

present results from a modeling scenario that reflects ozone-season 

NOX requirements in 26 states. This modeling differs from the final 

Transport Rule because it includes ozone-season NOX requirements for 

six states (Iowa, Kansas, Michigan, Missouri, Oklahoma, and 

Wisconsin) that the final Transport Rule does not cover (as discussed 

previously, EPA is issuing a supplemental proposal to request comment 

on inclusion of these six states). 

Table VIII.A-1 – Projected SO2 and NOX Electric Generating Unit 

Emission Reductions in Covered States with the Transport Rule 

Compared to Base Case without Transport Rule or CAIR (Million Tons)

2012 2012 2012 2014 2014 2014
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Base Case

Emissions

Transport 

Rule 

Emissions

Emission 

Reductions

Base Case 

Emissions

Transport 

Rule 

Emissions

Emission 

Reductions

SO2 7.0 3.0 4.0 6.2 2.4 3.9

Annual 

NOX

1.4 1.3 0.1 1.4 1.2 0.2

OzoneSeason 

NOX

0.7 0.6 0.1 0.7 0.6 0.1

Notes:

The SO2 and annual NOX emissions in this table reflect EGUs in the 23 

states covered by this rule for purposes of the 24-hour and/or annual 

PM2.5 NAAQS (Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, Minnesota, Missouri, Nebraska, New 

Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West Virginia, and Wisconsin).

The ozone-season NOX emissions reflect EGUs in the 20 states covered 

by this rule for purposes of the ozone NAAQS (Alabama, Arkansas, 

Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, 

Mississippi, New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West 

Virginia) and the six states that would be covered for the ozone 

NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas, 

Michigan, Missouri, Oklahoma, and Wisconsin).

Tables VIII.A-3 through VIII.A-5 present projected state-level 

emissions with and without the Transport Rule in 2012 and 2014 from 

fossil-fuel-fired EGUs greater than 25 MW in covered states.

Table VIII.A-2 – Projected SO2 and NOX Electric Generating Unit 

Emission Reductions in Covered States with the Transport Rule 

Compared to 2005 Actual Emissions (Million Tons)

2005 Actual 

Emissions

2012 

Transport 

Rule

Emissions

2012

Emission

Reductions 

from 2005

2014 

Transport 

Rule

Emissions

2014

Emission

Reductions 

from 2005

SO2 8.8 3.0 5.8 2.4 6.4

Annual 2.6 1.3 1.3 1.2 1.4
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NOX

OzoneSeason 

NOX

0.9 0.6 0.3 0.6 0.3

Notes:

The SO2 and annual NOX emissions in this table reflect EGUs in the 23 

states covered by this rule for purposes of the 24-hour and/or annual 

PM2.5 NAAQS (Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, Minnesota, Missouri, Nebraska, New 

Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West Virginia, and Wisconsin).

The ozone-season NOX emissions reflect EGUs in the 20 states covered 

by this rule for purposes of the ozone NAAQS (Alabama, Arkansas, 

Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, 

Mississippi, New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West 

Virginia) and the six states that would be covered for the ozone 

NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas, 

Michigan, Missouri, Oklahoma, and Wisconsin).

Table VIII.A-3 – Projected State-level Annual SO2 Emissions from 

Fossil-Fired Electric Generating Units Greater than 25 MW in Covered 

States in 2012 and 2014 in Base Case and with Transport Rule (tons)

Base Case Transport Rule

2012 2014 2012 2014

Alabama 455,503 417,009 219,067 173,231

Georgia 405,933 169,702 158,581 92,605

Illinois 485,417 137,522 209,701 128,143

Indiana 776,359 711,265 241,258 177,222

Iowa 121,663 127,354 75,003 77,931

Kansas 68,490 69,767 41,433 45,681

Kentucky 520,531 487,990 146,133 116,912

Maryland 49,942 42,926 26,630 30,368

Michigan 252,411 265,611 190,274 158,394

Minnesota 64,524 66,268 42,862 45,143

Missouri 375,771 381,939 181,662 177,359

Nebraska 70,754 71,821 65,079 70,087

New Jersey 26,346 38,857 5,518 6,243

New York 51,243 40,416 20,378 12,689

North Carolina 144,554 120,441 117,383 63,382

Ohio 871,401 831,648 230,216 150,784

Pennsylvania 493,206 507,360 250,484 123,224
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South Carolina 184,045 209,538 84,435 96,589

Tennessee 324,372 284,463 96,520 64,716

Texas 445,715 452,978 244,239 266,288

Virginia 80,889 64,917 66,640 38,562

West Virginia 535,586 497,398 119,174 83,235

Wisconsin 131,199 124,862 77,505 44,139

Total 6,935,853 6,122,051 2,910,173 2,242,927

Table VIII.A-4 – Projected State-level Annual NOX Emissions from 

Fossil-Fired Electric Generating Units Greater than 25 MW in Covered 

States in 2012 and 2014 in Base Case and with Transport Rule (tons)

Base Case Transport Rule

2012 2014 2012 2014

Alabama 82,005 74,937 73,600 68,119

Georgia 66,384 47,808 61,464 39,817

Illinois 51,969 54,661 47,635 48,533

Indiana 119,625 116,552 109,773 109,392

Iowa 42,563 44,614 36,953 38,302

Kansas 37,106 32,390 30,603 23,938

Kentucky 88,136 83,481 83,856 76,026

Maryland 16,602 17,444 15,665 17,061

Michigan 60,594 64,345 59,405 57,311

Minnesota 36,833 37,952 30,524 30,849

Missouri 53,199 54,528 51,329 48,888

Nebraska 42,985 43,410 26,488 26,552

New Jersey 7,391 7,858 7,355 7,562

New York 17,556 18,505 17,616 17,250

North Carolina 51,902 46,130 47,679 41,676

Ohio 100,420 99,389 84,679 84,126

Pennsylvania 129,125 132,299 117,612 116,994

South Carolina 34,635 37,862 33,144 35,591

Tennessee 37,674 29,256 32,984 20,490

Texas 136,124 140,788 133,406 136,638

Virginia 34,567 35,798 33,244 34,891

West Virginia 61,792 64,182 55,808 53,335

Wisconsin 36,701 36,904 30,643 29,688

Total 1,345,888 1,321,092 1,221,466 1,163,027

Table VIII.A-5 – Projected State-level Ozone-Season NOX Emissions from 

Fossil-Fired Electric Generating Units Greater than 25 MW in Covered 

States in 2012 and 2014 in Base Case and with Transport Rule (tons)

Base Case Transport Rule
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2012 2014 2012 2014

Alabama 34,074 31,365 31,607 29,532

Arkansas 15,037 16,644 15,087 16,728

Florida 41,646 45,993 27,645 29,435

Georgia 29,106 19,293 26,660 17,838

Illinois 21,371 22,043 21,102 21,210

Indiana 46,877 46,086 46,789 46,564

Iowa 18,307 19,440 15,746 16,346

Kansas 16,126 13,967 13,425 10,217

Kentucky 37,588 35,296 34,969 31,547

Louisiana 13,433 13,924 13,669 13,943

Maryland 7,179 7,540 6,705 7,248

Michigan 25,989 28,037 25,476 24,248

Mississippi 10,161 11,212 10,639 10,960

Missouri 23,156 23,759 21,788 20,805

New Jersey 3,440 3,668 3,403 3,518

New York 8,336 9,031 8,404 8,399

North Carolina 22,902 20,169 21,081 18,154

Ohio 42,274 41,327 34,576 35,769

Oklahoma 31,415 31,723 20,910 21,200

Pennsylvania 52,895 54,217 50,384 50,446

South Carolina 15,145 16,586 13,810 15,058

Tennessee 15,505 12,141 14,305 8,461

Texas 64,711 65,492 62,824 63,749

Virginia 15,148 15,339 14,311 14,744

West Virginia 26,464 27,099 23,352 22,406

Wisconsin 15,876 16,048 12,840 12,768

Total 654,161 647,439 591,508 571,293

B. The Impacts on PM2.5 and Ozone of the Final SO2 and NOX Strategy

The air quality modeling platform described in section V was 

used by EPA to model the impacts of the final rule SO2 and NOX

emission 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. 
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modeling domain91. Modeling was performed for the 2014 base case and 

the 2014 air quality-assured trading (i.e., remedy) scenario to 

assess the expected effects of the final rule 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 V. 

The projected 2014 concentrations of annual PM2.5, 24-hour PM2.5, 

and ozone at each monitoring site in the East for which projections 

were made are provided in the Air Quality Modeling Final Rule TSD. 

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, 

24-hour PM2.5, and ozone are provided in Table VIII.B-1.

92 The average 

and peak reductions in annual PM2.5, 24-hour PM2.5, and ozone predicted 

at 2012 nonattainment and/or maintenance sites due the emission 

reductions between 2012 and the 2014 remedy are provided in Table 

VIII.B-2.

Table VIII.B-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 

Remedy

Percent 

Reduction: 

2012 Base 

Case vs. 2014 

Remedy

Percent 

Reduction: 

2014 Base 

Case vs. 2014 

Remedy

 

91 As described in the Air Quality Modeling Final Rule TSD, 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.

92 To provide a point of reference, Table VIII.B-1 also includes the 

number of nonattainment and/maintenance sites based on ambient design 

values for the period 2003 through 2007.
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Annual PM2.5

Nonattainment 

Sites93

103 12 7 0 100 percent 100 percent

Annual PM2.5

MaintenanceOnly Sites22 4 3 0 100 percent 100 percent

24-hour PM2.5

Nonattainment 

Sites

151 20 10 1 95 percent 90 percent

24-hour PM2.5

MaintenanceOnly Sites48 21 12 4 81 percent 67 percent

Ozone 

Nonattainment 

Sites

104 7 4 4 43 percent No Change

Ozone 

MaintenanceOnly Sites65 9 6 6 33 percent No Change

Table VIII.B-2. Average and Peak Reduction in Annual PM2.5, 24-Hour 

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 2.73 μg/m3 3.32 μg/m3

Annual PM2.5 Maintenance-Only Sites 2.99 μg/m3 3.26 μg/m3

24-hour PM2.5 Nonattainment Sites 6.8 μg/m3 11.7 μg/m3

24-hour PM2.5 Maintenance-Only Sites 6.5 μg/m3 11.0 μg/m3

Ozone Nonattainment Sites 1.9 ppb 2.3 ppb

Ozone Maintenance-Only Sites

1.8 ppb 2.1 ppb

The information in Table VIII.B-1 shows that there will be 

significant reductions in the extent of nonattainment and maintenance 

 

93 “Nonattainment” is used to denote sites that are projected to have 

both nonattainment and maintenance problems.
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problems for annual PM2.5, 24-hour PM2.5, and ozone between 2012 and 

2014 as a result of the emission budgets in this rule coupled with 

emission reductions during this time period from other existing 

control programs. Specifically, the results of the air quality 

modeling indicate that no sites are projected to be in nonattainment 

or projected to have a maintenance problem for annual PM2.5 in 2014 

with the emission reductions expected from the Transport Rule. As 

indicated in Table VIII.B-2, the average reduction in annual PM2.5

across the twelve 2012 nonattainment sites is 2.73 μg/m3 and the peak 

reduction at an individual nonattainment site is 3.32 μg/m3. Large 

reductions are also 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 95 percent and the number of maintenanceonly sites by 81 percent in 2014 compared to the 2012 base case. The 

average reduction in 24-hour PM2.5 across the twenty 2012 

nonattainment sites is 6.8 μg/m3 and the peak reduction at an 

individual nonattainment site is 11.7 μg/m3. Similarly large 

reductions are projected at 24-hour PM2.5 maintenance-only sites, as 

indicated in Table VIII.B-2. 

The emission reductions in the Transport Rule will result in 

considerable progress toward attainment and maintenance at the 5

sites that remain as nonattainment and/or maintenance for the 24-hour 

PM2.5 standard. On average for these 5 sites, the predicted amount of 

PM2.5 reduction in 2014 is 64 percent of what is needed for these sites 

to attain and/or maintain the 24-hour standard.
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Thus, the SO2 and NOX emission reductions which will result from 

the Transport Rule will greatly reduce the extent of PM2.5

nonattainment and maintenance problems by 2014 and beyond. As 

described previously, these emission 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 emission 

reductions will also help those locations that may have maintenance 

problems.

Based on the 2012 base air quality modeling for ozone, 16 sites 

in the East are projected to be nonattainment or have problems 

maintaining the 1997 ozone standard. The summer NOX reductions are 

projected to lower 8-hour ozone concentration by 1.8 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 43 percent and the 

number of maintenance-only sites by 33 percent in 2014 compared to 

the 2012 base case. Thus, our modeling indicates that by 2014 the 

summer NOX emission reductions in this rule, coupled with other 

existing control programs, will lower ozone concentrations in the 

East and help bring areas closer to attainment for the 8-hour ozone 

NAAQS. As discussed in section III of this preamble, EPA plans to 

finalize its reconsideration of the 2008 revised ozone NAAQS soon, 

and these reductions will help areas achieve those revised NAAQS.
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C. Benefits

1. Human Health Benefit Analysis

To estimate the human health benefits of the final Transport 

Rule, EPA 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. 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 rule we cite two key empirical studies, one based on the 

American Cancer Society cohort study94 and the other based on the 

extended Six Cities cohort study.

95

The estimated benefits of this rule are substantial, 

particularly when viewed within the context of the total public 

health burden of PM2.5 and ozone air pollution. A recent EPA analysis 

estimated that 2005 levels of PM2.5 and ozone were responsible for 

between 130,000 and 320,000 PM2.5-related and 4,700 ozone-related 

 

94 Pope et al., 2002. ‘‘Lung Cancer, Cardiopulmonary Mortality, and 

Long-term Exposure to Fine Particulate Air Pollution.’’ Journal of 

the American Medical Association. 287:1132–1141.

95 Laden et al., 2006. ‘‘Reduction in Fine Particulate Air Pollution 

and Mortality.’’ American Journal of Respiratory and Critical Care 

Medicine. 173:667–672.
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premature deaths, or about 6.1 percent of total deaths from all 

causes in the continental U.S. (using the lower end of the range for 

premature deaths).96 In other words, 1 in 20 deaths in the U.S. is 

attributable to PM2.5 and ozone exposure. This same analysis 

attributed almost 200,000 non-fatal heart attacks, 90,000 hospital 

admissions due to respiratory or cardiovascular illness, 2.5 million 

cases of aggravated asthma among children, and many other human 

health impacts to exposure to these two air pollutants. 

We estimate that PM2.5 improvements under the Transport Rule 

will, starting in 2014, annually reduce between 13,000 and 34,000 

PM2.5-related premature deaths, 15,000 non-fatal heart attacks, 8,700 

incidences of chronic bronchitis, 8,500 hospital admissions, and 

400,000 cases of aggravated asthma while also reducing 10 million 

days of restricted activity due to respiratory illness and 

approximately 1.7 million work-loss days. We also estimate 

substantial health improvements for children from fewer cases of 

upper and lower respiratory illness and acute bronchitis.

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 27 and 120 fewer 

premature mortalities, 240 fewer hospital admissions for respiratory 

 

96 Fann N, Lamson A, Wesson K, Risley D, Anenberg SC, Hubbell BJ. 

Estimating the National Public Health Burden Associated with Exposure 

to Ambient PM2.5 and Ozone. Risk Analysis; 2011 In Press.
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illnesses, 86 fewer emergency room admissions for asthma, 160,000 

fewer days with restricted activity levels, and 51,000 fewer days 

where children are absent from school due to illnesses. 

Table VIII.C-1 presents the primary estimates of annual reduced 

incidence of PM2.5 and ozone-related health effects for the final rule

based on 2014 air quality improvements. When adding the PM and 

ozone-related mortalities together, we find that the Transport Rule 

will yield between 13,000 and 34,000 fewer premature mortalities 

annually. By 2014, in combination with other federal and state air 

quality actions, the Transport Rule will address a substantial 

fraction of the total public health burden of PM2.5 and ozone air 

pollution.

VIII.C-1 Estimated Annual Reductions in Incidences of Health Effects 

Based on 2014 Modelinga

Health Effect

Within transport 

region

Beyond 

transport 

region Total

PM-Related endpoints

Premature Mortality

Pope et al. (2002) 

(age >30)

13,000

(5,200—21,000)

33

(5—60)

13,000

(5,200—21,000)

Laden et al. (2006) 

(age >25)

34,000

(18,000—49,000)

84

(31—140)

34,000

(18,000—49,000)

Infant (< 1 year)

59

(-47—160)

0.15

(-0.2—0.5)

59

(-47—160)

Chronic Bronchitis

8,700

(1,600—16,000)

23

(-5—50)

8,700

(1,600—16,000)

Non-fatal heart attacks 

(age > 18)

15,000

(5,600—24,000)

40

(7—72)

15,000

(5,600—24,000)

Hospital admissions—

respiratory 

(all ages)

2,700

(1,300—4,000)

5

(2—9)

2,700

(1,300—4,000)
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Hospital admissions—

cardiovascular (age > 18)

5,700

(4,200—6,600)

15

(10—19)

5,800

(4,200—6,600)

Emergency room visits for 

asthma 

(age < 18)

9,800

(5,800—14,000)

21

(7—36)

9,800

(5,800—14,000)

Acute bronchitis 

(age 8-12)

19,000

(-630—37,000)

50

(-29—130)

19,000

(-660—37,000)

Lower respiratory symptoms 

(age 7-14)

240,000

(120,000—360,000)

630

(130—1,100)

240,000

(120,000—360,000)

Upper respiratory symptoms 

(asthmatics age 9-18)

180,000

(57,000—310,000)

480

(-25—980)

180,000

(57,000—310,000)

Asthma exacerbation 

(asthmatics 6-18)

400,000

(45,000—

1,100,000)

1,100

(-250—2,900)

400,000

(45,000—

1,100,000)

Lost work days 

(ages 18-65)

1,700,000

(1,500,000—

1,900,000)

4,300

(3,500—5,200)

1,700,000

(1,500,000—

1,900,000)

Minor restricted-activity 

days 

(ages 18-65)

10,000,000

(8,400,000—

11,000,000)

26,000

(20,000—

32,000)

10,000,000

(8,400,000—

12,000,000)

Ozone-related endpoints

Premature mortality Multi-city and NMMAPS

Bell et al. (2004) 

(all ages)

27

(11—42)

0.1

(0.01—0.3)

27

(11—42)

Schwartz et al. 

(2005) 

(all ages)

41

(17—64)

0.2

(0.1—0.4)

41

(17—65)

Huang et al. (2005) 

(all ages)

37

(17—57)

0.2

(0.1—0.4)

37

(17—57)

Meta-analyses

Ito et al. (2005) 

(all ages)

120

(78—160)

0.6

(0.3—0.9)

120

(79—160)

Bell et al. (2005) 

(all ages)

87

(48—130)

0.5

(0.2—0.8)

87

(48—130)

Levy et al. (2005) 

(all ages)

120

(89—150)

0.7

(0.4—0.9)

120

(90—160)

Hospital admissions—

respiratory causes (ages > 

65)

160

(21—280)

1.2

(0.1—2.3)

160

(21—290)

Hospital admissions—

respiratory causes (ages 

<2)

83

(43—120)

0.5

(0.2—0.8)

84

(43—120)

Emergency room visits for 

asthma (all ages)

86

(-2—260)

0.4

(-0.2—1.4)

86

(-2—260)

Minor restricted-activity 

days (ages 18-65)

160,000

(80,000—240,000)

910

(240—1,600)

160,000

(80,000—240,000)
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School absence days

51,000

(22,000—73,000)

290

(59—490)

51,000

(22,000—74,000)

a Values rounded to two significant figures. Benefits from reducing 

other criteria pollutants and hazardous air pollutants and ecosystem 

effects are not included here.

Source: EPA, 2011

2. Quantified and Monetized Visibility Benefits

Only a subset of the expected visibility benefits -— those for 

Class I areas -— are included in the monetary benefit 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 $4.1

billion beginning in 2014 for visibility improvements. The value of 

visibility benefits in areas where we are unable to monetize benefits 

could be substantial. 

3. Benefits of Reducing GHG Emissions 

When fully implemented in 2014, the Transport Rule will reduce 

emissions of CO2 from electrical generating units by about 25 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 
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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]. 

4. Total Monetized Benefits 

Table VIII.C-2 presents the estimated annual 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. Total monetized benefits are driven primarily by the reduction 

in premature fatalities each year, which account for between 89 and 

96 percent of total benefits. 
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VIII.C-2 Estimated Annual Monetary Value of Reductions in Incidence 

of Health and Welfare Effects Based on 2014 Modeling (Billions of 

2007$)A

Health Effect Pollutant

Within 

Transport Rule 

Region

Beyond Transport

Rule RegionB Total

Premature Mortality (Pope et al. 2002 PM mortality and Bell et al. 2004 ozone 

mortality estimates)

3% discount rate PM2.5 & O3

$100

($8.3—$320)

$0.3

($0.01—$0.9)

$100

($8.3—$320)

7% discount rate PM2.5 & O3

$94

($7.5—$280)

$0.2

($0.01—$0.8)

$94

($7.5—$290)

Premature Mortality (Laden et al. 2006 PM mortality and Levy et al. 2005 ozone 

mortality estimates)

3% discount rate PM2.5 & O3

$270

($23—$770)

$0.7

($0.05—$2)

$270

($23—$770)

7% discount rate PM2.5 & O3

$240

($21—$700)

$0.6

($0.05—$1.8)

$240

($21—$700)

Chronic Bronchitis PM2.5

$4.2

($0.2—$19)

$0.01

($-0.003—$0.06)

$4.2

($0.2—$19)

Non-fatal heart 

attacks 

3% discount rate PM2.5

$1.7

($0.3—$4.2)

$0.004

($0.003—$0.01)

$1.7

($0.3—$4.2)

7% discount rate PM2.5

$1.3

($0.3—$3.1)

$0.004

($0.002—$0.001)

$1.3

($0.3—$3.1)

Hospital 

admissions—

respiratory 

PM2.5 & O3

$0.04

($0.02—$0.06) ---

$0.04

($0.02—$0.06)

Hospital 

admissions—

cardiovascular 

PM2.5

$0.09

($0.01—$0.2) ---

$0.09

($0.01—$0.2)

Emergency room 

visits for asthma 

PM2.5 & O3

$0.003

($0.002—

$0.006)

---

$0.003

($0.002—$0.006)

Acute bronchitis PM2.5

$0.008

(<$-0.01—

$0.02)c

---

$0.008

(<$-0.01—$0.02)c

Lower respiratory 

symptoms 

PM2.5

$0.004

($0.002—

$0.009)

---

$0.004

($0.002—$0.009)

Upper respiratory 

symptoms 

PM2.5

$0.005

(<$0.01—

$0.014)

---

$0.005

(<$0.01—$0.014)

Asthma 

exacerbation 

PM2.5

$0.02

($0.002—$0.08) ---

$0.02

($0.002—$0.08)

Lost work days PM2.5

$0.2

($0.17—$0.24) ---

$0.2

($0.17—$0.24)

School loss days O3 $0.01 --- $0.01
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($0.004—

$0.013)

($0.004—$0.013)

Minor restrictedactivity days 

PM2.5 & O3

$0.7

($0.3—$1) ---

$0.7

($0.3—$1)

Recreational 

visibility, Class 

I areas

PM2.5 $4.1

Social cost of 

carbon (3% 

discount rate, 

2014 value)

CO2 $0.6

Monetized total Benefits 

(Pope et al. 2002 PM2.5 mortality and Bell et al. 2004 ozone mortality estimates)

3% discount rate PM2.5, O3

$110

($8.8—$340)

$0.28

($0.01—$0.9)

$120

($14—$350)

7% discount rate PM2.5, O3 

$100

($8—$310)

$0.25

($0.01—$0.85)

$110

($13—$320)

Monetized total Benefits 

(Laden et al. 2006 PM2.5 mortality and Levy et al. 2005 ozone mortality 

estimates)

3% discount rate PM2.5, O3

$270

($24—$800)

$0.7

($0.05—$2.1)

$280

($29—$810)

7% discount rate PM2.5, O3 

$250

($22—$720)

$0.6

($0.04—$1.9)

$250

($26—$730)

A Values rounded to two significant figures. Benefits from reducing 

other criteria pollutants and hazardous air pollutants and ecosystem 

effects are not included here.

B Monetary value of endpoints marked with dashes are < $100,000.

C The negative estimates for certain endpoints are the result of the 

weak statistical power of the study used to calculate these health 

impacts and do not suggest that increases in air pollution exposure 

result in decreased health impacts.

Source: EPA, 2011

5. How do the benefits in 2012 compare to 2014?

The magnitude of SO2 emission reductions achieved under the rule 

is actually larger in 2012 than in 2014, due to substantial emission 

reductions expected to occur in the baseline (i.e., unrelated to the 

Transport Rule) between those years. As a consequence, EPA expects 

correspondingly greater reductions in harmful effects to accrue in 

2012 compared to 2014.
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As presented in Table VIII.C-1, the Transport Rule is expected 

to prevent between 13,000 and 34,000 premature deaths annually from 

2014 onward due to reductions in ambient PM2.5 concentrations, which 

are most significantly impacted by SO2 emission reductions. Based on 

EPA's analysis of power sector emission reductions under the 

Transport Rule, the decline in SO2 in 2012 is 4 percent greater than 

the decline in SO2 in 2014 in the states modeled. EPA therefore 

anticipates that the Transport Rule will deliver greater reductions 

in ambient PM2.5 concentrations in 2012 and increased annual benefits 

to human health and welfare beyond those presented in this section.

6. How do the benefits compare to the costs of this final rule? 

The estimated annual private costs to implement the emission 

reduction requirements of the final rule for the Transport Rule 

states are $1.85 billion in 2012 and $0.83 billion in 2014 (2007 $). 

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 costeffectiveness 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 are estimated to be approximately $0.81 

billion in 2014 assuming either a 3 percent discount rate or a 7 

percent discount rate. Thus, the annual net benefit (social benefits 
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Page 438 of 1293

minus social costs) as shown in Table VIII.C-3 for the Transport Rule 

is approximately $120 to $280 billion or $110 to $250 billion (3 

percent and 7 percent discount rates, respectively) in 2014. 

Implementation of the rule is expected to provide society with a 

substantial net gain in social welfare based on economic efficiency 

criteria.

 A listing of the benefit categories that could not be 

quantified or monetized in our benefit estimates is provided in Table 

VIII.C-4.

Table VIII.C–3 Summary of Annual Benefits, Costs, and Net Benefits of 

the Final Transport Rule in 2014

(Billions of 2007$)a

Description Transport Rule Remedy (Billions of 2007 $)

3 % discount rate 7 % discount rate

Social costs $0.81 $0.81

Total monetized 

benefitsb $120 to $280 $110 to $250

Net benefits 

(benefits-costs)

$120 to $280 $110 to $250

a All estimates are for 2014, and are rounded to two significant 

figures.

b The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5 and ozone and the welfare 

benefits associated with improved visibility in Class I areas. The 

reduction in premature mortalities account for over 90 percent of 

total monetized PM2.5 and ozone benefits.

The annualized regional cost of the rule, as quantified here, is 

EPA’s best assessment of the cost of implementing the Transport Rule. 

These costs are generated from rigorous economic modeling of changes 

in the power sector expected from the rule. This type of analysis,
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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 

Transport Rule 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 be about $26

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 with the quantified 

costs of the program to the power sector. However, EPA’s experience 

and results of independent evaluation suggests that costs are likely 
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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 the RIA for this final

rule.

Every benefit-cost analysis examining the potential effects of a 

change in environmental protection requirements is limited to some 

extent by data gaps, 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, or 

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 emission inventories and air quality 

into the future; 
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• 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 value of a 

statistical life (VSL) estimates derived from 26 labor market and 

contingent valuation studies published between 1974 and 1991. The 

mean VSL across these studies is $6.3 million (2000$).97 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 VIII.C-2 indicates, total annual monetary 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: 

 

97 In this analysis, we adjust the VSL to account for a different 

currency year (2007$) and to account for income growth to 2014. After 

applying these adjustments to the $6.3 million value, the VSL is $8.7 

million.
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(1) EPA assumes inhalation of fine particles is causally 

associated with premature death at concentrations near those 

experienced by most Americans on a 24-hour 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 the 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 
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Page 443 of 1293

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 VIII.C-4.

Table VIII.C–4 Unquantified and Non-Monetized Effects of the 

Transport Rule

Pollutant/Effect Endpoint

PM: Healtha Low birth weight

Pulmonary function

Chronic respiratory diseases other than chronic 

bronchitis

Non-asthma respiratory emergency room visits 

UVb exposureb

PM: Welfare Household soiling

Visibility in residential areas

Visibility in non-class I areas and class 1 areas in 

NW, NE, and Central regions

UVb exposureb

Global climate impactsb

Ozone: Health Chronic respiratory damage

Premature aging of the lungs

Non-asthma respiratory emergency room visits

UVb exposureb

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 UVbb

Climate impacts
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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 effects

Commercial fishing, agriculture and forestry from 

nutrient deposition effects

Recreation in terrestrial and estuarine ecosystems 

from nutrient deposition effects

Other ecosystem services and existence values for 

currently healthy ecosystems Coastal eutrophication 

from nitrogen deposition effects

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 effects

Recreation in terrestrial and aquatic ecosystems from 

acid deposition effects

Increased mercury methylation

Mercury: Health Incidence of neurological disorders

Incidence of learning disabilities

Incidences in developmental delays

Mercury: Welfare Impact on birds and mammals (e.g., reproductive 

effects)

Impacts to commercial, subsistence and recreational 

fishing

Source: EPA

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 May result in benefits or disbenefits.

7. What are the unquantified and non-monetized benefits of the 

Transport Rule emission reductions? 
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Important benefits beyond the human health and welfare benefits 

quantified in this section and the RIA are expected to occur from 

this rule. These other benefits occur directly from NOX and SO2

emission reductions and from co-benefits due to Transport Rule 

compliance. These benefits are listed in Table VIII.C-4. Some of 

the more important examples include: reduced acidification and, in 

the case of NOX, eutrophication of water bodies; possible reduced 

nitrate contamination of drinking water; and reduced 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 EPA is 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, reduced mercury methylation and deposition, and reduced 

vegetation impairment from ozone. 

a. 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. These compounds are deposited onto terrestrial 
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and aquatic ecosystems across the U.S., contributing to the problems 

of acidification. 

(1) 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 depends largely on the 

watershed’s physical characteristics, such as geology, soils, and 

size. A key indicator of neutralizing ability is termed Acid 

Neutralizing Capacity (ANC). Higher ANC indicates greater ability to 

neutralize acidity. Acidic conditions occur more frequently during 

rainfall and snowmelt that cause high flows of water, and less 

commonly during low-flow conditions except where chronic acidity 

conditions are severe. Biological effects are primarily attributable 

to a combination of low pH and high inorganic aluminum 

concentrations. Biological effects of episodes include reduced fish 

condition factor -- changes in species composition and declines in 

aquatic species richness across multiple taxa, ecosystems and regions

-- as well as fish mortality. Waters that are sensitive to 

acidification tend to be located in small watersheds that have few 

alkaline minerals and shallow soils. Conversely, 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 
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action will decrease acid deposition within and downwind of the 

transport region and is likely to have positive effects on the health 

and productivity of aquatic ecosystems in the region. 

(2) 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.98 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,99

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 

 

98 U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated 

Science Assessment for Oxides of Nitrogen and Sulfur –Ecological 

Criteria National (Final Report). National 

Center for Environmental Assessment, Research Triangle Park, NC. 

EPA/600/R-08/139. December.

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.

99 Joslin, J.D., Kelly, J.M., van Miegroet, H. 1992. Soil chemistry 

and nutrition of North American spruce-fir stands: evidence for 

recent change. Journal of Environmental Quality, 21, 12-30.
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the soil due to accelerated leaching from 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. Acidifying deposition has been implicated as a 

causal factor.100

This regulatory action will decrease acid deposition within and 

downwind of the transport region and is likely to have positive 

effects on the health and productivity of forest systems in the 

region. 

b. 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. 

 

100 DeHayes, D.H., P.G. Schaberg, G.J. Hawley, and G.R. Strimbeck. 

1999. Acid rain impacts on calcium nutrition and forest health. 

Bioscience 49(10):789–800.
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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 nitrogen and phosphorus, and a majority of these 

estuaries are located in the coastal area from North Carolina to 

Massachusetts.101 For estuaries in the Mid-Atlantic region, the 

contribution of atmospheric distribution to total nitrogen loads is 

estimated to range between 10 percent and 58 percent.102

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 

 

101 National Oceanic and Atmospheric Administration (NOAA). 2007. 

Annual Commercial Landing Statistics. August. 

http://www.st.nmfs.noaa.gov/st1/commercial/landings/annual_landings.h

tml.

102 Valigura, R.A., R.B. Alexander, M.S. Castro, T.P. Meyers, H.W. 

Paerl, P.E. Stacy, and R.E. Turner. 2001. Nitrogen Loading in Coastal 

Water Bodies: An Atmospheric Perspective. Washington, DC: American 

Geophysical Union.
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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 within 

and downwind of the Transport Rule states. 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. 

c. Mercury Methylation and Deposition 
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Mercury is a highly neurotoxic contaminant that enters the food 

web as a methylated compound, methylmercury.103 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.104,105 The SO2 Integrated 

Science Assessment concluded that evidence is sufficient to infer a 

causal relationship between sulfur deposition and increased mercury 

methylation in wetlands and aquatic environments. 

d. Ozone Vegetation Effects 

Ozone causes discernible injury to a wide array of vegetation.106

In terms of forest productivity and ecosystem diversity, ozone may be 

 

103 U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated 

Science Assessment for Sulfur Oxides - Health Criteria (Final 

Report). National Center for Environmental Assessment, Research 

Triangle Park, NC. September. 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843.

104 Drevnick, P.E., D.E. Canfield, P.R. Gorski, A.L.C. Shinneman, D.R. 

Engstrom, D.C.G. Muir, G.R. Smith, P.J. Garrison, L.B. Cleckner, J.P. 

Hurley, R.B. Noble, R.R. Otter, and J.T. Oris. 2007. Deposition and 

cycling of sulfur controls mercury accumulation in Isle Royale fish. 

Environmental Science and Technology 41(21):7266–7272.

105 Munthe, J., R.A. Bodaly, B.A. Branfireun, C.T. Driscoll, C.C. 

Gilmour, R. Harris, M. Horvat, M. Lucotte, and O. Malm. 2007. 

Recovery of mercury-contaminated fisheries. AMBIO:A Journal of the 

Human Environment 36:33–44.

106 Fox, S., Mickler, R. A. (Eds.). 1996. Impact of Air Pollutants 

on Southern Pine Forests. Ecological Studies. (Vol. 118, 513 pp.) 

New York: Springer-Verlag.
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the pollutant with the greatest potential for regional-scale forest 

impacts.107 Studies have demonstrated repeatedly that ozone 

concentrations commonly observed in polluted areas can have 

substantial impacts on plant function.108,109

Assessing the impact of ground-level ozone on forests in the 

eastern United States involves understanding the risks to sensitive 

tree species from ambient ozone concentrations and accounting for the 

prevalence of those species within the forest. As a way to quantify 

the risks to particular plants from ground-level ozone, scientists 

have developed ozone-exposure/tree-response functions by exposing 

tree seedlings to different ozone levels and measuring reductions in 

growth as ‘‘biomass loss.’’ Typically, seedlings are used because 

they are easy to manipulate and measure their growth loss from ozone 

pollution. The mechanisms of susceptibility to ozone within the 

leaves of seedlings and mature trees are identical, and the decreases 

predicted using the seedlings should be related to the decrease in 

overall plant fitness for mature trees, but the magnitude of the 

 

107 U.S. Environmental Protection Agency (U.S. EPA). 2006. Air 

Quality Criteria for Ozone and Related Photochemical Oxidants 

(Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S. EPA. 

February. http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.

108 De Steiguer, J., Pye, J., Love, C. 1990. Air Pollution Damage to 

U.S. Forests. Journal of Forestry, 88(8), 17-22.

109 Pye, J.M. 1988. Impact of ozone on the growth and yield of trees: 

A review. Journal of Environmental Quality, 17, 347-360.
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effect may be higher or lower depending on the tree species.110 In 

areas where certain ozone-sensitive species dominate the forest 

community, the biomass loss from ozone can be significant. 

Significant biomass loss can be defined as a more than 2 percent 

annual biomass loss, which would cause long-term ecological harm, as 

the short-term negative effects on seedlings compound to affect longterm forest health.111

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. 

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.112 In addition, many businesses rely on healthy-looking 

vegetation for their livelihoods (e.g., horticulturalists, 

 

110 Chappelka, A.H., Samuelson, L.J. 1998. Ambient ozone effects on 

forest trees of the eastern United States: a review. New 

Phytologist, 139, 91-108.

111 Heck, W.W. &Cowling E.B. 1997. The need for a long term cumulative 

secondary ozone standard – an ecological perspective. Environmental 

Management, January, 23-33.

112 U.S. Environmental Protection Agency (U.S. EPA). 2007. Review of 

the National Ambient Air Quality Standards for Ozone: Policy 

assessment of scientific and technical information. Staff paper. 

Office of Air Quality Planning and Standards. EPA-452/R-07-007a. 

July. 

http://www.epa.gov/ttn/naaqs/standards/ozone/data/2007_07_ozone_staff

_paper.pdf.
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landscapers, Christmas tree growers, farmers of leafy crops, etc.) 

and a variety of ornamental species have been listed as sensitive to 

ozone.113

D. Costs and Employment Impacts

1. Transport Rule Costs and Employment Impacts

For the affected region, the projected annual private 

incremental costs of the rule to the power industry are $1.4 billion 

in 2012 and $0.8 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 2007 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 are estimated to be approximately $0.8 

billion annually in 2014. Overall, the economic impacts of the 

Transport Rule are modest in 2014, particularly in light of the large 

benefits ($120 to $280 billion annually at a 3 percent discount rate 

and $110 to $250 billion annually at a 7 percent discount rate) we 

expect, as shown in section XII.A of this preamble. Ultimately, we 

believe the electric power industry will pass along most of the costs 

 

113 Abt Associates, Inc. 2005. U.S. EPA. Urban ornamental plants: 

sensitivity to ozone and potential economic losses. Memorandum to 

Bryan Hubbell and Zachary Pekar.
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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 final rule, refer to 

section XII.H (Statement of Energy Effects) later in this preamble.

For this 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.

EPA also included an analysis of impacts of the final rule to 

industries outside of the electric power sector by using the MultiMarket Model. This model is a partial equilibrium economic impact 

model that includes 100 sectors that cover energy, manufacturing, and 

service applications and is designed to capture the short-run effects 

associated with an environmental regulation. This model was used to 

estimate economic impacts for the proposed MATS, and the promulgated 

industrial boilers major and area source standards and CISWI 

standard.

We use the Multi-Market Model to estimate the social costs of 

the final rule. Using this model, we estimate the social costs of 

the final rule to be approximately $0.8 billion (2007 dollars), which 

is close to the compliance costs. Documentation for the Multi-Market 

Model can be found in the RIA for this final rule.
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Also note that as explained in section V.B (Baseline for 

Pollution Transport Analysis), the baseline used in this analysis 

assumes no CAIR. 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).

Although a stand-alone analysis of employment impacts is not 

included in a standard cost-benefit analysis, the current economic 

climate has led to heightened concerns about potential job impacts. 

Such an analysis is of particular concern in the current economic 

climate as sustained periods of excess unemployment may introduce a 

wedge between observed (market) wages and the social cost of labor. 

In such conditions, the opportunity cost of labor required by 

regulated sectors to bring their facilities into compliance with an 

environmental regulation may be lower than it would be during a 

period of full employment (particularly if regulated industries 

employ otherwise idled labor to design, fabricate, or install the 

pollution control equipment required under this rule). For that 

reason, EPA also includes estimates of job impacts associated with 

the final rule. EPA presents an estimate of short-term employment 

opportunities as a result of increased demand for pollution control 

equipment. Overall, the results suggest that the final rule could 

support a net increase of roughly 2,250 job-years in direct 

employment in 2014. 
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The basic approach to estimate these employment impacts involved 

using projections from IPM from the final rule analysis such as the 

amount of capacity that will be retrofit with control technologies, 

for various energy market implications, along with data on labor and 

resource needs of new pollution controls and labor productivity from 

secondary sources, to estimate employment impacts for 2014. This 

analysis was also applied for the proposed MATS. For more 

information, refer to Appendix D of the RIA for the final Transport 

Rule.”

EPA relied on Morgenstern, et al. (2002), a study that is a 

basis for employment impacts estimated for the final industrial 

boiler major and area source rules and CISWI standard, and the 

proposed MATS. The Morgenstern study identifies three economic 

mechanisms by which pollution abatement activities can indirectly 

influence jobs: (1) higher production costs raise market prices, 

higher prices reduce consumption, and employment within an industry 

falls (“demand effect”); (2) pollution abatement activities require 

additional labor services to produce the same level of output (“cost 

effect”); and (3) post regulation production technologies may be more 

or less labor intensive (i.e., more/less labor is required per dollar 

of output) (“factor-shift effect”).

Using plant-level Census information between the years 1979 and 

1991, Morgenstern, et al., estimate the size of each effect for four 

polluting and regulated industries (petroleum, plastic material, pulp 

and paper, and steel). On average across the four industries, each 
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additional $1 million spending on pollution abatement results in a 

small net increase of 1.6 jobs; however, the estimated effect is not 

statistically significant. As a result, the authors conclude that 

increases in pollution abatement expenditures do not necessarily 

cause economically significant employment changes. The conclusion is 

similar to Berman and Bui (2001), who found that increased air 

quality regulation in Los Angeles did not cause large employment 

changes. For more information, please refer to the RIA for this 

final rule.

 The ranges of job effects calculated using the Morgenstern, et 

al., approach are listed in Table VIII.D-1.

Table VIII.D-1. Range of Job Effects for the Electricity Sector

Estimates 

using 

Morgenstern, 

et al. (2002)

Demand Effect Cost Effect Factor Shift 

Effect

Net Effect

Change in 

Full-Time 

Jobs per 

Million 

Dollars of 

Environmental 

Expenditurea

−3.56 2.42 2.68 1.55

Standard 

Error

2.03 0.83 1.35 2.24

EPA Estimate 

for Final 

Ruleb

+200 to -

3,000

+400 to 2,000 0 to 2,000 -1,000 to 

+3,000

a Expressed in 1987 dollars. See footnote a of Table 8-3 in the RIA 

for the inflation adjustment factor used in the analysis.
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b According to the 2007 Economic Census, the electric power 

generation, transmission, and distribution sector (NAICS 2211) had 

approximately 510,000 paid employees.

EPA recognizes there may be other job effects which are not 

considered in the Morgenstern, et al., study. Although EPA has 

considered some economy-wide changes in industry output as shown 

earlier with the Multi-Market model, we do not have sufficient 

information to quantify other associated job effects associated with 

this rule.

2. End-Use Energy Efficiency

EPA believes that achievement of energy efficiency (EE)

improvements in homes, buildings, and industry is an important 

component of achieving emission 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 final rule, and reduces the 

need for investments in EGU emission control technologies in order to 

meet emission reduction requirements. Moreover, energy efficiency 

can often be implemented at a lower cost than traditional control 

technologies. 

EPA recognizes that significant opportunities remain for energy 

efficiency improvements in businesses, homes, and industry. However, 

there are several informational and market barriers that limit 

investment in cost-effective energy efficient practices. Several
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federal programs authorized under the CAA, including ENERGY STAR, are 

designed to address these barriers. 

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 MidAtlantic regions) -– have provided mechanisms for rewarding energy 

efficiency through either the award of allowances, typically through 

the use of a fixed set-aside pool, or the use of revenues obtained 

through the auction of allowances. The emission caps established by 

these programs are unaffected by this approach. However, to the 

extent electricity demand reductions are realized, compliance costs 

are reduced. In addition to these allowance-based programs, EPA has 

also provided guidance114 concerning the recognition, in SIPs, of 

emission reduction benefits of energy efficiency and has approved the 

inclusion of EE measures in individual SIPs.115

While all remedy options considered in the proposed rule would 

have lead to an increase in the relative cost-effectiveness of EE 

 

114 U.S. EPA. 2004. Guidance on State Implementation Plan (SIP) Credits 

for Emission Reductions from Electric-Sector Energy Efficiency and 

Renewable Energy Measures. 

http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf

115 Metropolitan Washington Council of Governments developed a regional 

air quality plan for the eight-hour ozone standard for the DC Region 

nonattainment area that included an EE measure. The plan was adopted 

by Virginia, Maryland, and the District of Columbia and the 

respective ozone SIPs were approved by the EPA regions in 2007.
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investments by internalizing environmental costs associated with 

emission of these pollutants, EPA took comment on whether EPA has 

authority, and whether it would be appropriate for EPA, to consider 

EE in developing the allowance allocation methodology and to consider 

other approaches for encouraging EE in the Transport Rule.

Some commenters suggested that EPA has authority to consider EE 

in developing the allocation methodology. Other commenters do not 

believe EPA has the authority to consider EE. Some commenters 

suggested that EPA should establish an EE set-aside provision. Other 

commenters suggested that EPA should allow, and help, states to 

establish EE set-asides as states transition from Transport Rule FIPs 

to SIPs. EPA believes that, while EE set-asides can be effective at 

encouraging incremental investments in EE, EE set-asides are more 

likely to be practically and effectively implemented at the state 

level. Establishing EE set-asides in the allowance allocation 

provisions in the final rule would not allow for the tailoring of the 

set-asides to the unique characteristics of individual states and 

would not build on the existing EE program delivery infrastructure 

that many states already possess. Instead of establishing EPAadministered EE set-asides in the final rule, EPA is clarifying that 

it allows and supports EE set-asides (including auction-based 

approaches) in abbreviated or full SIPs that states may submit, as 

provided in the final rule. Under this approach states have the 

ability to implement EE set-asides tailored to their state 
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circumstances, if they choose. EPA anticipates providing additional 

information in the future for states on EE set-asides, as needed.116

As discussed elsewhere in this preamble, the final rule provides 

for submission and approval of abbreviated and full SIPs providing 

for continued state participation in the Transport Rule trading 

programs, and adopting alternative allowance allocation methodologies 

(which may include EE set-asides) to the allocation methodologies 

adopted in the FIPs. While the final rule establishes certain 

requirements for approval of any such alternative allocation 

methodology, the final rule provides states flexibility to create 

state-implemented EE set-asides. 

IX. Related Programs and the Transport Rule

A. Transition from the Clean Air Interstate Rule

1. Key Differences between the Transport Rule and CAIR

The Transport Rule replaces CAIR and its associated trading 

programs. There are a number of differences between implementation 

of the Transport Rule and implementation of CAIR. This section 

describes key implementation differences including differences in 

states covered, compliance deadlines, applicability, structure of the 

remedy, provisions for early reductions, and provisions for SIPs. 

 

116 Because the question of EPA authority to create EE set-asides in 

the FIPs would be best addressed in the context of actual FIP 

provisions for EPA-created EE set-asides and EPA is, for other 

reasons, not adopting such provisions in the final rule, EPA is not 

addressing in the final rule the question of EPA’s authority.
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The next section discusses the transition from CAIR to the Transport 

Rule.

States covered. The states covered by the Transport Rule differ 

somewhat from states covered by CAIR. This section summarizes 

differences in state coverage. EPA’s approach to determine states 

covered by the Transport Rule is discussed in sections V and VI of 

this preamble.

The Transport Rule’s SO2 and annual NOX requirements apply to 

covered sources in the 23 states listed in Table III-1 in section III 

of this preamble. CAIR’s SO2 and annual NOX requirements applied to 

covered sources in 25 states. There are many states in common 

between the Transport Rule and CAIR SO2 and annual NOX programs. The 

differences are summarized in Table IX.A-1.

Table IX.A-1 - Differences in SO2 and Annual NOX State Coverage 

between the Transport Rule and CAIR

State Transport Rule SO2 and 

Annual NOX Programs 

CAIR SO2 and Annual NOX 

Programs

Kansas Yes No

Minnesota Yes No

Nebraska Yes No

Delaware No Yes

District of Columbia No Yes

Florida No Yes

Louisiana No Yes

Mississippi No Yes
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The Transport Rule’s ozone-season NOX requirements apply to 

covered sources in the 20 states listed in Table III-1 in section III 

of this preamble, while CAIR’s ozone-season NOX requirements applied 

to 26 states. There are many states in common between the Transport 

Rule and CAIR ozone-season NOX programs. The differences are 

summarized in Table IX.A-2. 

Table IX.A-2 - Differences in Ozone-Season NOX State Coverage between 

the Transport Rule and CAIR

State Transport Rule OzoneSeason NOX Program CAIR Ozone-Season NOX

Program

Georgia Yes No

Texas Yes No

Connecticut No Yes

Delaware No Yes

District of Columbia No Yes

Iowa No Yes

Massachusetts No Yes

Michigan No Yes

Missouri No Yes

Wisconsin No Yes

In addition, EPA is proposing a supplemental notice to apply 

Transport Rule ozone-season requirements to the states of Iowa, 

Kansas, Michigan, Missouri, Oklahoma, and Wisconsin, as discussed in 

section III of this preamble.

The transition from CAIR to the Transport Rule is discussed in 

section IX.A.2 and SIPs are discussed in section X of this preamble.
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Compliance deadlines. The Transport Rule reduction requirements 

commences January 1, 2012 for annual NOX and SO2 requirements and May 

1, 2012 for ozone-season NOX requirements. More stringent SO2

reduction requirements commence January 1, 2014 for Group 1 states.

In contrast, the first phase of CAIR NOX reductions commenced 

January 1, 2009 for annual NOX requirements and May 1, 2009 for ozoneseason NOX requirements. On January 1, 2010, the first phase of CAIR 

SO2 requirements commenced. However, in anticipation of CAIR, SO2

reductions actually started as early as 2006 because of the incentive 

to reduce emissions and bank Title IV Acid Rain Program SO2 allowances 

for use when their value would increase under CAIR in 2010 and later. 

The second phase of CAIR reductions would have (if not replaced by 

the Transport Rule) commenced January 1, 2015 for annual NOX and SO2

requirements, and May 1, 2015 for ozone-season NOX requirements.

Applicability. Except for the changes to the states covered, 

the general applicability provisions of the final Transport Rule 

trading programs are essentially the same as the CAIR general 

applicability provisions, with a few exceptions.

First, the final Transport Rule does not allow any non-covered 

units to opt into the trading programs, for the reasons discussed in 

section VII.B of this preamble. In contrast, under CAIR, through 

SIPs, the 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.
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Second, the Transport Rule FIPs’ ozone-season NOX trading program 

applicability provisions do not cover NOX SIP Call small EGUs and nonEGUs that a number of CAIR states brought into the CAIR ozone-season 

NOX trading program. The Transport Rule does allow any state in the 

ozone-season NOX program, through SIPs, to expand the applicability of 

the Transport Rule ozone-season NOX trading program to cover small 

EGUs. However, the Transport Rule does not allow states to expand 

the applicability to cover NOX SIP Call non-EGUs, for the reasons 

discussed elsewhere in this preamble.

In contrast, in the CAIR trading programs, a NOX SIP Call state 

could expand the applicability of the CAIR ozone-season NOX trading 

program in the state in order to include all units subject to the NOX

Budget Trading Program under the NOX SIP Call. A number of states 

chose to expand the CAIR ozone-season NOX trading program 

applicability in this way. The transition from CAIR to the Transport 

Rule is discussed in section IX.A.2 and SIPs are discussed in section 

X of this preamble.

Structure of the remedy. The CAIR FIPs (and CAIR model trading 

rules adopted by a number of states in their CAIR SIPs) implemented 

reductions through SO2, annual NOX, and ozone-season NOX interstate 

emission trading programs covering primarily large EGUs. The owners 

and operators of a covered source could buy allowances from or sell 

allowances to other covered sources (or other market participants) 

and were required to surrender allowances equal to the source’s 

emissions for each compliance period. CAIR’s trading programs did 
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not impose limitations on the aggregate emissions from covered units 

within any covered state.

The Transport Rule FIPs will also achieve the required 

reductions through SO2, annual NOX, and ozone-season NOX interstate 

trading programs. However, in contrast to CAIR and for the reasons 

discussed in section VII of this preamble, the Transport Rule FIPs 

include assurance provisions specifically designed to ensure that no 

state’s emissions will exceed that state’s emission budget plus the 

variability limit, i.e., the state’s assurance level.

Another difference in the remedy structure is in the design of 

the SO2 trading programs. In CAIR all of the states required to 

reduce SO2 emissions were grouped together in one SO2 trading program 

with no restriction on the use of SO2 allowances from any state in the 

program by any source in the program. In contrast, and for the 

reasons discussed in section VI of this preamble, the Transport Rule 

divides states required to reduce SO2 emissions into two groups with 

emission reduction requirements of different stringency starting in 

2014 (SO2 Group 1, whose reduction requirements become more stringent 

starting in 2014, and SO2 Group 2, whose reduction requirements in 

2014 do not change). A covered source may only use for compliance --

with the requirements to hold allowances covering emissions and, if 

applicable, to surrender allowances under the assurance provisions --

an SO2 allowance issued for the SO2 Group in which the source’s state 

is included. In other words, an SO2 Group 1 source may only use a SO2
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Group 1 allowance for compliance, and likewise an SO2 Group 2 source 

may only use a SO2 Group 2 allowance for compliance.

Provisions for early reductions. CAIR included provisions for 

covered sources to make early reductions prior to the start of CAIR’s 

SO2 and NOX trading programs, bank emission allowances, and carry 

banked allowances into its trading programs. In contrast, the 

Transport Rule does not include provisions for covered sources to 

carry over any allowances (i.e., Title IV SO2 allowances or CAIR 

annual or ozone-season NOX allowances) into the Transport Rule trading 

programs. EPA’s reasons for not allowing the use of banked Title IV 

SO2 allowances or CAIR annual or ozone-season NOX allowances in the 

Transport Rule trading programs are discussed in the next section.

Provisions for SIPs. The following is a summary of the key 

differences between the Transport Rule and CAIR provisions for SIPs. 

A more detailed discussion of Transport Rule SIPs is in section X of 

this preamble.

The SIP provisions in the Transport Rule and CAIR are very 

similar. Both include provisions that allow states to submit SIP 

revisions (referred to as full SIPs) that replace an applicable FIP 

trading program with a comparable SIP trading program that has 

certain limited differences from the FIP trading program. Similarly, 

both rules include provisions that allow states to submit SIP 

revisions (referred to as abbreviated SIPs) that may modify certain 

limited provisions in the FIP trading program, which remain in place. 

Inclusion of this provision in the Transport Rule allows a state to 
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modify certain elements of a Transport Rule FIP trading program in 

order to better meet the needs of the state. Both the Transport Rule 

and CAIR allow full or abbreviated SIPs that involve one or more 

applicable FIP trading programs. However, there are a few 

differences.

In particular, under the Transport Rule, states may submit SIP 

revisions under which the state determines allocations for the 

applicable trading program using either full or abbreviated SIP 

revisions. States could submit similar revisions under CAIR. Under 

the Transport Rule, the state may use the same allocation methodology 

as that currently used in the Transport Rule FIP trading program or 

some other allocation methodology. However, the Transport Rule 

specifies certain requirements that must be met concerning, for 

example, the timing of such allocation determinations, and expressly 

allows allowance auctions to be used. CAIR did not include similar 

provisions. Further, the SIP submission deadlines, allocation 

submission, and allocation recordation dates are different between 

the Transport Rule and CAIR. The Transport Rule SIP submission 

deadlines and allocation recordation dates are discussed in section X 

of this preamble.

In addition, both the Transport Rule and CAIR include provisions 

that allow states to submit SIP revisions under which the state 

expands the general applicability provisions of the ozone-season NOX

trading programs to cover certain units subject to the NOX SIP Call. 

However, for the reasons discussed elsewhere in this preamble, this 
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flexibility is more limited in the Transport Rule than it was in 

CAIR.

While CAIR allowed states to adopt, through full or abbreviated 

SIPs, opt-in provisions, the Transport Rule does not allow for opt-in 

provisions. The reasons for this are discussed in section VII.B of 

this preamble.

Finally, neither full nor abbreviated SIPs can replace FIP 

provisions that apply to units in Indian country within the borders 

of a state. For example, the FIPs include, for states within whose 

borders Indian country is located, an Indian country new unit setaside. For states not having Indian country within their borders, 

abbreviated SIPs are limited to replacing the allowance allocation 

provisions of the FIPs for the state involved and may replace some or 

all of those provisions. However, for states having Indian country 

within their borders, abbreviated SIPs cannot replace the FIP 

provisions for the Indian country new unit set-aside. Similarly, for 

states not having Indian country, full SIPs can replace an entire 

FIP, but, in doing so, can only change the allowance allocation 

provisions. For states having Indian country, full SIPs can replace 

the FIPs except for the Indian country new unit set-aside provisions, 

which will remain under the applicable FIPs, and, like the 

abbreviated SIPs, can only change the allowance allocation provisions 

that are replaced.
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Details of the Transport Rule provisions for abbreviated and 

full SIP revisions, including deadlines for submission to EPA, are 

discussed in section X of this preamble.

2. Transition from the Clean Air Interstate Rule to the Transport 

Rule

The Transport Rule replaces CAIR and its associated trading 

programs. This section elaborates on areas of transition from CAIR 

to the Transport Rule.

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

The proposal explained that, for control periods in 2012 and 

thereafter, CAIR, CAIR SIPs, and CAIR FIPs would be replaced entirely 

by the Transport Rule provisions. The proposal outlined 

implementation of the sunsetting of CAIR and CAIR FIPs, through 

revisions to CAIR, §§ 51.123 and 51.124, and the CAIR FIPs, §§ 52.35 

and 52.36. For the control period in these years, the CAIR trading 

programs would not continue, and 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 CAIR. Offset and automatic penalty provisions under 

CAIR would not apply to excess emissions for 2011 control periods. 

Also discussed were the processes for modifying provisions in 

Part 52 reflecting state-specific CAIR SIP and CAIR FIP requirements, 

which would vary depending on whether a state has an approved CAIR 

SIP or a CAIR FIP. The proposal further explained that sources in 

some states covered by CAIR or the CAIR FIPs would not be subject to 
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the Transport Rule and that to the extent that 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 is finalizing regulatory changes to sunset CAIR and the CAIR 

FIPs. The final rule revises the general CAIR and CAIR FIP 

provisions in Parts 51 and 52 applicable to all CAIR states. For 

control periods in 2012 and thereafter, the Administrator rescinds 

the determination that states must meet SIP requirements under CAIR, 

and the requirements of the CAIR FIPs are not applicable. Further, 

with regard to these control periods, the Administrator will no 

longer 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 CAIR with the exception of 

enforcing the provisions for the previous control periods, if 

necessary. 

For the reasons discussed in the proposed rule preamble (75 FR 

45337), CAIR allowances allocated for these control periods cannot be 

used in any CAIR trading program and, as discussed below, in any 

Transport Rule trading program. Specifically, for the reasons 

discussed in the proposed rule, offset and automatic allowance 

penalty provisions in the CAIR trading programs will not be applied 

to 2011 control period excess emissions, which will remain subject to 

discretionary civil penalties under CAA section 113. EPA still 

retains all enforcement options for excess emissions during the 2011 

control period. CAIR allowances allocated for 2012 and thereafter 
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are not usable in any CAIR or Transport Rule trading program. In 

light of that fact, in order to prevent any confusion by owners and 

operators and other members of the public concerning the status of 

such allowances, the final rule provides that, within 90 days after 

publication of the final Transport Rule, the Administrator will 

remove post-2011 CAIR annual NOX and ozone-season allowances from the 

Allowance Tracking System.

 The CAIR SO2 trading program, of course, uses Acid Rain 

allowances, which will remain in the Allowance Tracking System 

because they were created by CAA Title IV and continue to be usable 

in the Acid Rain Program. 

The final rule also adopts the discussion in the proposed rule 

concerning state-specific Part 52 provisions concerning CAIR (75 FR 

45337-38). With regard to Part 52 provisions reflecting EPA’s 

adoption of ongoing CAIR FIPs for some individual states, the final 

rule revises the CAIR FIP provisions to make them inapplicable to 

control periods in 2012 and thereafter and to require the 

Administrator to remove from the Allowance Tracking System, CAIR 

allowances for these control periods. The final, state-specific CAIR 

FIP provisions in Part 52 essentially echo the language in the final, 

general CAIR provisions in Part 52 discussed above. In making the 

CAIR FIP provisions inapplicable to control periods in 2012 and 

thereafter, the final, state-specific provisions sunset the 

applicable CAIR FIP trading programs whether or not the CAIR FIPs 

were revised by approved, abbreviated CAIR SIPs. (Under CAIR, 
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abbreviated CAIR SIPs were adopted by certain states so that states, 

rather than EPA, made NOX allowance allocations.) Consequently, 

states with approved, abbreviated CAIR SIPs will not need to revise 

their abbreviated CAIR SIPs in order to sunset the CAIR trading 

programs to which these abbreviated SIPs applied. Thus, although 

such abbreviated SIPs may remain in the state SIPs, they will have no 

force and effect, once the CAIR FIPs sunset.

With regard to Part 52 provisions reflecting EPA’s approval of 

full CAIR SIPs submitted to EPA by many individual states, the 

Court’s North Carolina decision essentially overrides these Agency 

approvals of individual CAIR SIPs. (Under CAIR, full CAIR SIPs were 

adopted by certain states to replace CAIR FIPs and continue 

participation through the CAIR SIPs in the CAIR trading programs.)

The Court found CAIR to be illegal and only allowed it to remain in 

effect temporarily. For this reason, the CAIR SIPs though approved, 

can have no force and effect once CAIR is replaced by this rule. For 

this reason, although the proposed rule indicated that states would 

need to submit SIP revisions to, among other things, make the CAIR 

SIPs inapplicable to control periods after 2011, the final rule does 

not require states to take any actions to revise their full or 

abbreviated CAIR SIPs. For states covered by CAIR or CAIR FIPs that 

are not subject to the Transport Rule and have relied on CAIR 

reductions to satisfy other SIP requirements, EPA will discuss with 

states alternative ways to satisfy requirements for those SIP 

requirements, e.g., through intrastate cap and trade programs that 
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require the level of reductions on which the state has recently 

relied.

b. NOX SIP Call Units

The NOX Budget Trading program was used by states to reduce 

ozone-season NOX emissions from EGUs and large non-EGUs under NOX SIP 

Call requirements. The program started in 2003 and ended in 2008. 

Under CAIR, a state subject to the NOX SIP Call was allowed to expand 

the applicability of the CAIR ozone-season NOX trading program in the 

state in order to include all units subject to the NOX Budget Trading 

Program 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 ozone-season NOX 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. EPA proposed to not allow this 

expansion in applicability for the Transport Rule, primarily because 

these sources as a group did not actually reduce emissions for the NOX

Budget Trading Program or CAIR. EPA took comment on the proposed 

approach.

Several commenters generally advocated allowing, at state 

discretion, all NOX Budget Trading Program units to be regulated under 

the Transport Rule ozone-season NOX trading program. Some also 

questioned how states would otherwise satisfy NOX SIP Call 

requirements for these units. Some commenters argued that some units 

did in fact make emission reductions in the NOX Budget Trading 

Program, but did not provide information on specific units. 
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The final rule provides states an option to expand the general 

applicability provisions of the Transport Rule ozone-season NOX

trading program to cover small EGUs, but not other units in the NOX

SIP Call. Specifically, consistent with the comments, EPA determined 

that it is appropriate to allow states to expand the applicability of 

the Transport Rule ozone-season NOX trading program to include units 

serving a generator with a nameplate capacity equal to or greater 

than 15 MWe producing electricity for sale. This will allow states 

with NOX SIP Call obligations to meet those requirements with respect 

to these small EGUs. These units can be brought into the program 

through abbreviated or full Transport Rule SIPs. However, if a state 

chooses to expand the general applicability provisions, the state 

Transport Rule ozone-season NOX budget cannot be increased. EPA 

believes that the level of emissions from small EGUs is sufficiently 

small that the existing Transport Rule state budget can accommodate 

these units. This is consistent with the approach taken in the NOX

Budget Trading Program, where the states that added these small EGUs 

did not increase their NOX SIP Call EGU budgets. This also removes 

concern (expressed in the proposed rule) that increasing state 

budgets in the Transport Rule ozone-season NOX trading program, as 

part of the expansion of the applicability provisions to include 

small EGUs, would jeopardize elimination of a state’s significant 

contribution to nonattainment and interference with maintenance. 

With regard to large non-EGUs that were included in the NOX

Budget Trading Program (the remainder of the sources in the NOX Budget 
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Trading Program), the final Transport Rule, like the proposed rule, 

does not allow expansion of the general applicability provisions for 

the ozone-season NOX trading program to include such units. As 

explained in the proposed rule (75 FR 43340), while some of these 

units may have installed controls around the start of the NOX Budget 

Trading Program, EPA analysis shows that, as a group, these units did 

not collectively reduce emissions, their current emission rates are 

nearly identical to their emission rates before the start of the NOX

Budget Trading Program, and their allocations are about twice their 

emissions, with the result that the excess allocations were sold to 

covered EGUs.117 Moreover, EPA believes that there are little or no 

emission reductions available by non-EGUs at the cost thresholds used 

in the final rule and so no basis for developing non-EGUs state 

budgets reflecting the elimination of significant contribution to 

nonattainment and interference with maintenance. For these reasons, 

the final rule allows states to expand the ozone-season NOX trading 

program to cover small EGUs that were in the NOX Budget Trading 

Program, but not to cover large non-EGUs that were in that program. 

As explained in the proposed rule, if a state were to do so, 

emissions from these units could jeopardize elimination of the 

state’s significant contribution to nonattainment or interference 

 

117 Although the proposed rule discussed the EPA analysis in the 

context of considering the treatment of both small EGUs and large 

non-EGUs from the NOX Budget Trading Program, the analysis actually 

addresses, and draws conclusions about emission reductions, emission 

rates, and allowance allocations concerning only large non-EGUs. 
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with maintenance. See 75 FR 45340. For states that relied on large 

non-EGUs for emission reductions required by the NOX SIP Call, EPA 

will assist in identifying ways to ensure continued, future 

compliance with the NOX SIP Call requirements.

c. Early Reduction Provisions

Substantial emission reductions have occurred as a result of 

previous emission trading programs, under both Title IV and 

CAIR. This has lead to substantial “banks” of allowances (i.e., 

holdings of unused allowances allocated for years before the 

programs sunset) in each of the CAIR programs. In the proposal, 

EPA requested comment on whether to allow banked CAIR allowances 

to be used in the Transport Rule trading programs. EPA 

recognizes the importance of continuity in emission trading 

programs as a general principle. However, for the reasons 

explained below, EPA has decided not to allow banked CAIR 

allowances to be used in any of the Transport Rule trading 

programs. (1) SO2 Allowance Bank

The bank of Title IV allowances was more than 12 million tons at 

the end of 2009. This bank is the result of emission reductions 

under the Title IV Acid Rain Program. Under the CAIR SO2 trading 

program, EPA allowed banked (as well as future year) Title IV 

allowances to be used in the CAIR SO2 trading program -- in lieu of 

being used in the Acid Rain Program -- for compliance with the 

requirement to hold allowances covering SO2 emissions. This approach 
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encouraged early reductions for the CAIR SO2 trading program, but was 

held to be unlawful in North Carolina.

In the proposed rule, EPA took comment on whether sources should 

be allowed to use banked Title IV allowances in the Transport Rule SO2

program. EPA proposed to 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, in part, 

because EPA was concerned that those approaches would be perceived as 

inconsistent with the requirements of CAA section 110(a)(2)(D)(i)(I) 

as interpreted by the Court in North Carolina. See 75 FR 45338-39.

A number of commenters advocated that EPA recognize Title IV 

allowance holdings in the Transport Rule, either by allowing full or 

limited carryover of the allowances or by allocating all or a portion 

of the Transport Rule SO2 allowances based on Title IV allowance 

holdings. Other commenters agreed with EPA’s assessment that 

allowing Title IV allowance carryover in the Transport Rule is 

inconsistent with North Carolina and that any linkage of Transport 

Rule allocations with Title IV allowance holdings would carry 

unnecessary, significant legal risk. Therefore, for the reasons 

explained above and in the proposal, EPA has decided not to permit 

sources to use Title IV allowances for compliance with the Transport 

Rule SO2 trading programs. 

In addition, unlike CAIR, in the Transport Rule, EPA decided not 

to base allocation of Transport Rule SO2 allowances on the specific 

distribution of existing title IV allowances. Title IV allowances 
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continue, of course, to be usable for compliance in the Acid Rain 

Program.118

(2) NOX Allowance Banks

In the proposed rule, EPA estimated that the CAIR ozone-season 

NOX bank would contain over 600,000 allowances and the CAIR annual NOX

bank would contain about 720,000 allowances after completion of trueup of allowance holdings and emissions for 2011. EPA considered the 

alternatives of allowing or not allowing pre-2012 CAIR NOX allowances 

and CAIR ozone-season NOX allowances to be used in the Transport Rule 

NOX trading programs.

EPA also described and requested comment on several possible 

approaches for handling banked pre-2012 CAIR NOX allowances in the 

Transport Rule NOX trading programs and the pros and cons of each (75 

FR 45339): 

 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 its 

significant contribution to nonattainment and interference with 

maintenance;

 Allow only a limited amount of banked pre-2012 CAIR allowances 

to be brought into the Transport Rule NOX programs;

 

118 The Title IV allowance bank is expected to be about 14 million tons 

at the beginning of 2012.
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 Factor the bank into the calculation of state NOX budgets by 

reducing the state NOX budgets to take account of the banked pre2012 CAIR allowances; and

 Do not allow the use of any banked pre-2012 CAIR allowances in 

the Transport Rule NOX programs. 

EPA proposed the last of these approaches and requested comment on 

all of the described approaches or suggestions on other ways to 

handle banked pre-2012 CAIR allowances in the Transport Rule NOX

programs.

 Many commenters advocated allowing the carryover of CAIR NOX

allowances to the Transport Rule. Reasons given included: 

preservation of early reduction investments; need for market 

continuity; increased flexibility during program start up and 

early years of the programs; preservation of the credibility of, 

and certainty under, trading approaches; and the lack of a 

prohibition in North Carolina of carryover of CAIR NOX

allowances. Commenters also suggested that surrender ratios be 

used to limit the amount, and negative effects, of a carryover.

 Many other commenters were against allowing CAIR NOX allowance 

carryover into the Transport Rule. Reasons given included: 

unnecessary, significant legal risk; concerns about the efficacy 

of the Transport Rule if state budgets are supplemented by a 

carryover; and differences in the nature of the programs (the NOX

Budget Trading Program, which addressed the 1-hour ozone NAAQS, 
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and the CAIR ozone-season NOX trading program, which addressed 

the 1997 8-hour ozone NAAQS and was reversed in North Carolina) 

under which the allowances were banked, and the Transport Rule 

ozone-season NOX trading program, which addresses the 1997 8-hour 

ozone NAAQS.

For the reasons explained below, after evaluating all comments 

on this issue, EPA decided not to allow the use of CAIR NOX allowances 

in the Transport Rule NOX trading programs. EPA reevaluated the 

estimated size of the potential carryover (allowances that will 

remain unused in the CAIR programs at the end of 2011 compliance 

periods), taking into account 2010 emissions. EPA estimates that 

more than 440,000 CAIR ozone-season NOX allowances will remain and 

that more than 460,000 CAIR annual NOX allowances will remain at the 

end of the 2011 compliance periods. EPA considered whether to allow 

these CAIR ozone-season NOX and CAIR annual NOX allowances to be used 

in the Transport Rule NOX trading programs. The CAIR ozone-season NOX

allowances expected to remain unused represent nearly three-quarters 

of aggregate state ozone-season NOX budgets119 in a single year under 

the final Transport Rule. The allowances expected to remain unused 

in the annual NOX program represent more than one-third of aggregate 

state annual NOX budgets in a single year under the Transport Rule. 

 

119 This analysis is for all states identified to be contributing 

significantly to nonattainment or interfering with maintenance. When 

the analysis is conducted using the aggregate state budgets for only 

those states for which we are finalizing ozone season requirements in 

this rule, the percentage increases.
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As discussed in the proposal, if these allowances were carried over 

in addition to the Transport Rule state budgets, EPA could not be 

assured that significant contribution to nonattainment or 

interference with maintenance would be eliminated. EPA therefore 

rejects any approach under which all banked CAIR NOX allowances would 

be added to the Transport Rule trading programs on top of each 

state’s annual NOX and/or ozone-season NOX budgets.

In response to public comments, EPA considered whether the 

Transport Rule trading programs should allow some form of exchange of 

banked CAIR annual NOX and ozone-season allowances for new Transport 

Rule NOX allowances within each state’s annual NOX and/or ozone-season 

budgets, respectively. However, EPA believes that this type of 

approach carries substantial legal and technical problems. First, 

the state-by-state distribution of CAIR NOX allowances resulted from 

the methodology applied by EPA in CAIR of using fuel factors to set 

the total amounts of allowance allocations in each state (i.e., the 

state NOX budgets). The CAIR NOX allowance banks therefore are -- at 

least in part -- the result of this methodology, which was reversed 

in North Carolina. See North Carolina, 531 F.3d at 918-22. Thus, 

EPA did not use fuel factors in developing the Transport Rule state 

budgets. However, EPA is concerned that the distribution of some or 

all Transport Rule NOX allowances through exchanges of banked CAIR NOX

allowances for Transport Rule NOX allowances would blur the bright 

line between the methodology used for setting budgets in the 

Transport Rule and the methodology used for setting budgets in CAIR 
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that was rejected by the Court. At least to some extent, the parties 

that were advantaged under EPA’s budget-setting methodology in CAIR 

would continue to have an advantage under the Transport Rule by 

receiving more Transport Rule NOX allowances. EPA therefore believes 

that allowing exchange of banked CAIR NOX allowances for Transport 

Rule NOX allowances carries significant legal risk.

Second, establishing a procedure for exchanging banked CAIR NOX

allowances for Transport Rule NOX allowances within each state’s 

budget would mean that Transport Rule NOX allowances could not be 

allocated until after completion of the process for determining 

compliance with allowance-holding requirements for 2011 in the CAIR 

NOX trading programs. This process cannot begin until after the 

allowance transfer deadline for the 2011 control periods (i.e., March 

1, 2012 for the CAIR annual NOX program and November 1, 2011 for the 

CAIR ozone-season NOX program) and will not likely be completed until 

mid-2012. At that time, EPA could begin the procedure of 

implementing, state-by-state, the exchanges of the remaining CAIR NOX

allowance banks held by parties (owners and operators, brokers, and 

other entities) for some or all of the allowances in the state NOX

budgets for 2012. The portion of each state budget that would be 

used up by such exchanges would likely vary from state to state. The 

resulting delay, and uncertainty about the unit-by-unit amounts, of 

Transport Rule NOX allowance allocations for 2012 would undermine 

Transport Rule allowance market liquidity, significantly disrupt 

planning by owners and operators for compliance with allowance-
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holding requirements for the 2012 control periods, and likely impose 

increased compliance costs under the Transport Rule NOX trading 

programs or impact the ability to comply with the 2012 limits. 

In light of the specific circumstances in this case and the 

above-described legal and technical problems that would result from a 

carryover of CAIR NOX allowances into the Transport Rule trading 

programs, the final rule does not allow any such carryover. EPA 

agrees that, as a general principle, it is desirable to provide 

continuity between sequential regulatory programs involving emission 

trading and thereby to ensure that allowances in the past program 

continue to have some value in the new program. Balancing the 

general desirability of providing program continuity against the 

potential negative consequences of a carryover in, and the specific 

circumstances of, this case, EPA concludes that the carryover of 

banked CAIR NOX allowances into the Transport Rule trading programs 

should not be allowed. EPA notes that, in this case, it signaled 

the possibility that it would take such an approach in order to 

provide markets with full information and avoid unnecessary 

disruptions. After CAIR was remanded by the Court in North Carolina, 

550 F.3d 1176, in December 2008, EPA was concerned about the future 

status of CAIR NOX allowances and consequently advised the public --

through a statement posted on the EPA website in March, 2009 -- that 

“EPA's continued recording of CAIR NOX allowances does not guarantee 

or imply that any allowances will continue to be usable for 

compliance after a replacement rule is finalized or that they will 
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continue to have value in the future.”121 EPA believes its decision to 

disallow carryover of banked allowances here reflects the specific 

factors in this case and should not be treated as setting any 

precedent for the treatment, in any future trading programs, of any 

past trading program’s banked allowances.

However, EPA notes that, under the CAIR ozone-season NOX trading 

program, where unused allowances were carried forward from the 

preceding NOX Budget Trading Program, and under the CAIR annual NOX

trading program, where extra allowances (from the compliance 

supplement pool) were allocated for early reductions made during the 

NOX Budget Trading Program, the vast majority of allowance allocation 

decisions were made by the states administering these programs. 

Moreover, a number of states did not allocate CAIR allowances to 

their sources using fuel adjustment factors, whose use the Court 

rejected in North Carolina in connection with EPA’s setting of state 

NOX emission budgets. 

In light of the general desirability of providing continuity 

between state programs, states may want to address the CAIR NOX banks 

when developing, in SIP revisions, the Transport Rule allowance 

allocations for control periods after 2012. EPA encourages each 

state that wants to allocate Transport Rule NOX allowances through SIP 

 

121http://epa.gov/airmarkets/business/cairallowancestatus.html. EPA 

posed similar statements in the on-line systems for trading CAIR NOX

allowances. See 40 CFR 96.102 and 96.302 (definitions of “CAIR NOX

Allowance Tracking System” and “CAIR NOX Ozone Season Allowance 

Tracking System”).
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revisions to consider using information on the CAIR NOX allowance 

banks that will remain after 2011. Any such allowance allocations, 

of course, must be within the respective state’s NOX trading budget, 

and must be submitted to EPA within the applicable submission 

deadlines, established in the final rule for the control periods for 

which the allocations are made. The Agency intends to contact states 

concerning the desirability of holding a workshop to discuss issues 

related to state allowance allocations.

B. Interactions with NOX SIP Call

The proposed rule explained that states covered by both the NOX

SIP Call and the Transport Rule would be required to comply with the 

requirements of both rules and that the Transport Rule would not 

preempt or replace the requirements of the NOX SIP Call. Most, but 

not all, NOX SIP Call states would be included in the Transport Rule. 

The proposed rule further explained that the Transport Rule ozoneseason NOX trading program would achieve the emission reductions 

required by the NOX SIP Call from EGUs serving generators with a 

nameplate capacity greater than 25 MW and producing electricity for 

sale in most NOX SIP Call states. (This would not be the case, of 

course, for those NOX SIP Call states not covered by the Transport 

Rule.)

The NOX SIP Call states used the NOX Budget Trading Program 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/hour. (In 
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some states, EGUs serving a generator with a nameplate capacity of 25 

MW or less were also included in the NOX Budget Trading Program as a 

carryover from the Ozone Transport Commission NOX Budget Trading 

Program.) EPA stopped administering the NOX Budget Trading Program 

under the NOX SIP Call after the completion of compliance activities 

related to the 2008 ozone-season control period, and states used 

other mechanisms to comply with the NOX SIP Call requirements.

The proposal further explained that, if EPA promulgated a final 

rule that did not allow the expansion of the Transport Rule to NOX

Budget Trading Program units, any state that allowed these units to 

participate in the CAIR ozone-season NOX trading program would need to 

submit a SIP revision to address the state’s NOX SIP Call requirement 

for the reductions. The proposal also explained that states in the 

CAIR ozone-season NOX trading program or the NOX Budget Trading 

Program that would not be in the Transport Rule ozone-season NOX

trading program would need to submit SIP revisions addressing the NOX

SIP Call requirements for any emission reductions (by EGUs and nonEGUs) addressed in the NOX Budget Trading Program and not addressed in 

some other way. See 75 FR 45340-41.

As discussed elsewhere in this preamble, the final Transport 

Rule allows states to expand the general applicability provisions of 

the Transport Rule ozone-season NOX trading program to include small 

EGUs, which were included by some states in the NOX Budget Trading 

Program, but not for large non-EGUs, which were included in the NOX

Budget Trading Program. This will allow states with NOX SIP Call 
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obligations to meet those requirements with respect to small EGUs 

brought into the Transport Rule trading program, but not with regard 

to large non-EGUs. 

With the issuance of the final Transport Rule, NOX SIP Call 

requirements remain in place. See 40 CFR 51.121. EPA is not 

changing any of the NOX SIP Call requirements. The NOX SIP Call 

generally requires that states choosing to rely on large EGUs and 

large non-EGUs for meeting NOX SIP Call emission reduction 

requirements must establish a NOX mass emissions cap on each source 

and require Part 75, subpart H monitoring. As an alternative to 

source-by-source NOX mass emissions caps, a state may impose NOX

emission rate limits on each source and use maximum operating 

capacity for estimating NOX mass emissions or may rely on other 

requirements that the state demonstrates to be equivalent to either 

the NOX mass emissions caps or the NOX emission rate limits that 

assume maximum capacity. Collectively, the caps or their 

alternatives cannot exceed the portion of the state budget for those 

sources. See 40 CFR 51.121(f)(2) and (i)(4). EPA will work with 

states to ensure that NOX SIP Call obligations continue to be met 

(e.g., through intrastate cap and trade programs that require the 

level of reductions on which the state has recently relied).

C. Interactions with Title IV Acid Rain Program

The final rule does not affect any Acid Rain Program 

requirements. Acid Rain Program requirements are established 

independently in Title IV of the CAA and are not replaced by the 
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Transport Rule. Title IV sources that are subject to final Transport 

Rule provisions still need to continue to comply with all Acid Rain 

provisions. Title IV SO2 and NOX requirements continue to apply 

independently of the Transport Rule provisions. For the reasons 

explained above, Title IV SO2 allowances are not allowed to be used in 

the Transport Rule trading programs. Similarly, Transport Rule SO2

allowances are not usable in the Acid Rain Program.

The final Transport Rule does not include any opt-in unit 

provisions in the FIPs and does not allow SIP revisions to include 

opt-in unit provisions in the Transport Rule trading programs. 

Consequently, no sources, including those that have opted in to the 

Acid Rain Program, can opt-in to the Transport Rule trading programs.

There will likely be changes to emissions at some Acid Rain 

units 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 units in the states that border the 

Transport Rule states may increase because of potential load-shifting 

from units in Transport Rule states and because of a potential 

decrease in the Title IV allowance price. There is a discussion of 

possible emission increases in non-covered states in section VI.C of 

this preamble.

D. Other State Implementation Plan Requirements

In this final action, EPA has not conducted any technical 

analysis to determine whether compliance with the Transport Rule 

would satisfy RACT requirements for EGUs in any nonattainment areas, 
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or Regional Haze BART-related requirements. For that reason, EPA is

neither making determinations nor establishing any presumptions that 

compliance with the Transport Rule satisfies any RACT or BART-related 

requirements for EGUs. Based on analyses that states conduct on a 

case-by-case basis, states may be able to conclude that compliance 

with the Transport Rule for certain EGUs fulfills nonattainment area 

RACT requirements. EPA intends to undertake a separate analysis to 

determine if compliance with the Transport Rule would provide 

sufficient reductions to satisfy BART requirements for EGUs in 

accordance with Regional Haze Rule requirements for alternative BART 

compliance options as soon as practicable following promulgation of 

the Transport Rule.

X. Transport Rule State Implementation Plans

EPA proposed (75 FR 45342) FIPs setting state-specific emission 

reduction requirements for each upwind state covered by the proposed 

Transport Rule and 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. In the 

proposed Transport Rule, EPA proposed to allow similar flexibility to 

states for addressing the CAA section 110(a)(2)(D)(i)(I) transport 

issues through a SIP. EPA proposed to 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 with the specific 

quantity of emission reductions necessary for a state’s SIP 
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determined based on the state emission budgets provided in the final 

Transport Rule.

EPA received comments suggesting that if the proposal’s remedy 

were finalized, EPA should allow states to replace the FIP allowance 

allocation provisions in the proposed Transport Rule trading programs 

by state-developed allocation provisions. Commenters referenced the 

two alternatives provided to states in the CAIR trading programs 

where: (1) EPA adopted a rule and model trading regulations under 

which states that adopted, as state SIP trading programs, the model 

regulations (with only certain limited changes allowed, e.g., in the 

allocation provisions) could participate in the EPA-administered CAIR 

trading programs; and (2) EPA adopted a rule allowing states to adopt 

in SIPs provisions replacing only certain provisions in the CAIR FIPs 

(e.g., the allocation provisions) and to remain in the CAIR trading 

programs under the CAIR FIPs. Under both approaches, the covered 

units in the state participated in the CAIR trading programs, albeit 

with state-, rather than EPA-, determined allocations. Comments on 

the Transport Rule proposal supported these two types of approaches 

for allowing states to replace EPA allocations under the proposed 

Transport Rule trading programs by state allocations. EPA requested 

additional comment on this topic in the NODA published January 7, 

2011 (76 FR 1109).

Two approaches with associated deadlines were explained in the 

NODA. Under the first approach, EPA would adopt new provisions, as 

part of the proposed Transport Rule FIP that would allow a state to 
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submit a SIP (referred as an abbreviated SIP) that would modify 

specified provisions of the proposed Transport Rule FIP trading 

programs. Specifically, the abbreviated SIP would substitute state 

allocation provisions for control periods in years after 2012, 

applicable to one or more of the proposed Transport Rule FIP trading 

programs that apply to the state. The NODA explained which specific 

provisions in the FIP could be replaced. If the state allocation 

provisions met certain requirements and the abbreviated SIP did not 

change any other provisions in the respective proposed Transport Rule 

FIP trading program, then EPA would approve the abbreviated SIP. In 

the substitute state allocation provisions, the state could allocate 

allowances to Transport Rule units (whether existing or new units) or 

other entities (such as renewable energy facilities) or could auction 

some or all of the allowances. The NODA went on to describe the 

requirements for EPA approval of an abbreviated SIP (76 FR 1119) 

including that the total amount of allowances allocated and auctioned 

each year could not exceed the applicable budget; allocations and 

auction results would need to be reported to EPA by the permitting 

authority (usually the state) by particular dates prior to the 

applicable control period depending on whether allowances were going 

to existing or new sources; the reported allocations and auction 

results could not be changed; and no other provisions of the FIP 

would be changed.

Under the second approach, EPA would adopt a new rule that would 

provide that, if a state submitted a SIP (referred to as a full SIP) 
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that adopted trading program regulations meeting certain requirements 

for control periods in years after 2012, then EPA would approve the 

full SIP as correcting the deficiency under CAA section 

110(a)(2)(D)(i)(I) in the state’s SIP that was the basis for issuance 

of the comparable proposed Transport Rule FIP. In the state 

allocation provisions, the state could allocate allowances to 

Transport Rule units (whether existing or new units, except for optin units) or other entities (such as renewable energy facilities) or 

could auction allowances. Upon EPA approval of a state’s full SIP, 

the state’s SIP-based trading program would be integrated with the 

comparable FIP-based Transport Rule trading program (whether or not 

modified by an abbreviated SIP) covering other states. Moreover, 

covered sources in the state could participate in the integrated 

trading program, and the allowances issued under the SIP-based state 

trading program would be interchangeable with the allowances issued 

in the comparable FIP-based Transport Rule trading program.

The NODA went on to describe the limited changes that states 

could make under the full SIP option. Only allocation provisions 

could be modified with the same requirements as for abbreviated SIPs,

including, among other things, that the total amount of allowances 

allocated each year could not exceed the applicable budget and that 

allocations would need to be reported to EPA by the permitting 

authority (usually the state) by particular dates prior to the 

applicable control period depending on whether allowances were going 

to existing or new sources.
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The NODA also discussed the option for states to submit SIPs 

using emission reduction approaches other than the proposed Transport 

Rule trading programs to correct the deficiency under CAA section 

110(a)(2)(D)(i)(I) in the state’s SIP. EPA would review on a caseby-case basis SIPs using such alternative approaches (76 FR 1120).

Suggested deadlines for abbreviated and full SIPs were given in 

tables in the NODA (76 FR 1120). These deadlines generally required 

states to submit SIPs about 2 years ahead of a particular control 

period for which state allocations would apply in order to give EPA 

time to review and approve the SIP and record allowances.

Most commenters on the NODA supported state allocation options, 

within the preferred FIP remedy, that would replace FIP allocations 

with SIP-based state allocations.

In the final rule, EPA adopts, with some revisions, both of the 

approaches described in the January 7, 2011 NODA. Under the first 

approach, a state may submit an abbreviated SIP that modifies a final 

Transport Rule FIP trading program in only a limited way (i.e., by 

replacing the allowance allocation provisions in §§97.411(a) and 

(b)(1) and 97.412(a) for the annual NOX trading program, §§97.511(a) 

and (b)(1) and 97.512(a) for the ozone-season NOX trading program, 

§§97.611(a) and (b)(1) and 97.612(a) for the SO2 Group 1 trading 

program, and §§97.711(a) and (b)(1) and 97.712(a) for the SO2 Group 2 

trading program). In the state’s replacement provisions, the state 

may allocate allowances to Transport Rule units (whether existing or 
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new units)122 or other entities (such as renewable energy facilities) 

or may auction allowances. Additionally, state SIPs can address one 

or all of the pollutants addressed by the FIPs. For PM2.5, EPA is 

finalizing the flexibility for a state SIP to address either SO2 or 

NOX, or both. Further, if a state is required to make ozone-season 

and annual NOX reductions, the SIP could address either ozone-season 

or annual NOX emissions, or both. In other words, states can replace 

provisions in all FIPs that apply or some subset of the FIPs that 

apply to a particular state, and leave in place the FIPs for the 

requirements not addressed by a SIP.

Further, EPA will approve the abbreviated SIP only if the state 

replacement for the Transport Rule FIP allocation provisions meets 

certain requirements and the abbreviated SIP does not change any 

other provisions in the Transport Rule FIP trading program. For EPA 

approval, the state allocation and, where applicable, auction 

provisions (and any accompanying definitions of terms applying only 

to terms as used in these provisions) must meet the following 

requirements. First, the provisions must provide that, for each year 

for which the state allocation and, where applicable, auction 

provisions will apply, the total amount of control period (annual or 

ozone-season) allowances allocated and, where applicable, auctioned 

in accordance with these provisions cannot exceed the applicable 

state budget (less any applicable Indian country new unit set-aside, 

 

122 EPA is not finalizing opt-in provisions, so the reference to 

federal-only opt-in allocations in the NODA has been removed.
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which will continue to be administered by EPA) for that year under 

the relevant Transport Rule FIP trading program.

Second, to the extent the state provisions provide for 

allocations for, or auctions open to, existing units, the provisions 

must require that the state or the permitting authority under title V 

of the CAA for the state submit to the Administrator final 

allocations and, if any auction is to be held, final auction results 

in accordance with a schedule of deadlines discussed below. To the 

extent the provisions provide for allocations for or auctions open to 

new units or any other entities, the provisions must require that the 

permitting authority submit to the Administrator final allocations 

and, if applicable, auction results by July 1 of the year of the 

control period for which the allowances will be distributed. The 

allocation and auction results must be final and cannot be subject to 

modification (e.g., through an allowance surrender adjusting the 

allocation or auction results).

As noted above, the state’s submission to the Administrator of 

allocations or auction results with regard to existing units must 

meet a specified schedule of deadlines. These submission deadlines 

reflect, and are necessarily coordinated with, the deadlines for 

recordation by the Administrator of allowance allocations and any 

auction results under the Transport Rule trading programs. The 

recordation deadlines, which are discussed in detail in section XI of 

this preamble, provide that the Administrator must record existingunit allowance allocations and auction results by: July 1, 2013 for 
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the applicable control periods in 2014 and 2015; July 1, 2014 for the 

applicable control periods in 2016 and 2017; July 1, 2015 for the 

applicable control periods in 2018 and 2019; and July 1, 2016 and 

July 1 of each year thereafter for the control period in the fourth 

year after the year of the applicable recordation deadline. In order 

to provide the Administrator 1 month to review the submissions of 

allocations and auction results to ensure that the submissions 

include sufficient information (e.g., the correct identification for 

each unit involved) to record correctly the submitted allocations and 

auction results, the state or permitting authority must make these 

submissions to the Administrator by: June 1, 2013 for the applicable 

control periods in 2014 and 2015; June 1, 2014 for the applicable 

control periods in 2016 and 2017; June 1, 2015 for the applicable 

control periods in 2018 and 2019; and June 1, 2016 and June 1 of each 

year thereafter for the applicable control period in the fourth year 

after the year of the applicable submission deadline. 

Under the second approach, a state may submit a full SIP 

adopting a Transport Rule trading program that differs from the 

comparable Transport Rule FIP trading program only with regard to 

limited provisions of the FIP trading program. First, the full SIP 

may include new allocation or auction provisions instead of the 

Transport Rule FIP allowance allocation provisions other than those 

concerning the Indian country new unit set-aside. In the state 

allocation or auction provisions, the state may allocate allowances 

to Transport Rule units (whether existing or new units) or other 
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entities (such as renewable energy facilities) or may auction 

allowances. EPA will approve the full SIP only if the state 

allocation or auction provisions (and any accompanying definitions of 

terms applying only to terms as used in these provisions) meet 

certain requirements. Second, the full SIP may substitute the name 

of the state for the term “State” as used in the FIP trading program 

provisions, provided that EPA determines that the substitutions are 

not substantive changes. Third, as discussed in more detail below, 

all references to units in Indian country, as used in the FIP trading 

program provisions, must be removed, and the full SIP cannot impose 

any requirements on units in Indian country within the borders of the 

state and may not include the Indian country set-aside provisions. 

Other than these allowed changes, all other provisions in the 

Transport Rule trading program in the full SIP must be the same as 

those in the Transport Rule FIP trading program with regard to nonIndian country units. For EPA approval, the state allocation 

provisions must meet the same requirements, as discussed above, that 

state allocation or auction provisions in an abbreviated SIP must 

meet.

A Transport Rule trading program adopted by a state in a full 

SIP, and approved by EPA, under the second approach will be fully 

integrated with the comparable Transport Rule FIP trading program 

(i.e., the “TR NOX Annual Trading Program”, “TR NOX Ozone Season 

Trading Program”, “TR SO2 Group 1 Trading Program”, or “TR SO2 Group 2 

Trading Program” respectively) for other states. This will apply 
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whether the comparable Transport Rule FIP program for other states 

was modified by an abbreviated SIP approved by EPA under the first 

approach or was not modified by such an abbreviated SIP. The 

integration of these three types of trading programs will be 

accomplished primarily through the definitions of the terms, ‘‘TR NOX

Annual allowance’’, ‘‘TR NOX Ozone Season allowance”, ‘‘TR SO2 Group 1 

allowance’’, and ‘‘TR SO2 Group 2 allowance’’ in the full SIPs 

approved by EPA and the TR FIP trading programs (whether or not the 

programs were modified by abbreviated SIPs). ‘‘TR NOX Annual 

allowance’’ will be defined in the state and Transport Rule FIP 

trading programs as including allowances issued under any of the 

following trading programs: the comparable EPA-approved state 

Transport Rule trading programs; the comparable Transport Rule FIP 

trading programs with EPA-approved state allocation and auction 

provisions; and the Transport Rule FIP trading programs with EPA 

allocation provisions. Similarly, the definitions in the state and 

Transport Rule FIP trading programs of ‘‘TR NOX Ozone Season 

allowance’’, ‘‘TR SO2 Group 1 allowance’’, and ‘‘TR SO2 Group 2 

allowance’’ respectively will include allowances issued under all 

three types of trading programs. As a result, allowances issued in 

one approved state Transport Rule trading program will be 

interchangeable with allowances issued in the comparable Transport 

Rule FIP trading program (whether or not modified by an abbreviated 

SIP), and all these allowances will be available for use for 

compliance with the allowance-holding requirements (to cover 
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emissions and to meet assurance provision requirements) in all three 

types of trading programs.

The integration of state and the proposed Transport Rule FIP 

trading programs will also be reflected in the definitions of ‘‘TR NOX

Annual Trading Program,’’ ‘‘TR NOX Ozone Season Trading Program’’, 

‘‘TR SO2 Group 1 Trading Program’’, and ‘‘TR SO2 Group 2 Trading 

Program’’. Each of these definitions in the state Transport Rule and 

Transport Rule FIP trading programs will expressly encompass the 

comparable Transport Rule FIP trading programs (whether or not 

modified by an abbreviated SIP) and the comparable EPA-approved state 

full SIP trading program.

The final rule also sets deadlines for the submission of 

complete abbreviated and full SIPs. These deadlines are based on the 

first year for which the state wants to allocate or auction 

allowances, reflect the above-discussed deadlines for the 

Administrator’s recordation of allocations and auction results, and 

build in a 6-month period for EPA review, provision of notice and 

opportunity for public comment, and approval of the SIP revisions. 

This 6-month period is built into the final rule’s SIP submission 

deadlines because that is the period EPA found was needed for 

reviewing, providing notice and comment for, and approving state 

trading program provisions in abbreviated and full SIPs under CAIR. 

As a result, the final rule requires that complete abbreviated and 

full SIPs must be submitted to the Administrator by: December 1, 

2012 in order to govern allowance allocation and auction for control 
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periods in 2014 and 2015; December 1, 2013 in order to govern control 

periods in 2016 and 2017; December 1, 2014 in order to govern 

allowance allocation and auction for control periods in 2018 and 

2019; and December 1, 2015 and by December 1 of any year thereafter 

in order to govern allowance allocation and auction for control 

periods in the fifth year after such submission deadline.

EPA notes that, in cases where a state that has Indian country 

within its borders submits, and EPA approves, a full SIP, the 

comparable FIP will not be entirely replaced. In such cases, the FIP 

will continue to be in place with regard to the Transport Rule 

trading program provisions that concern units in Indian country, and 

the full SIP will encompass all other provisions of the trading 

program. Specifically, to the extent Transport Rule trading program 

provisions reference and apply to Indian country units (including, 

for example, references in the applicability provisions and the 

Indian country new unit set-aside provisions), those provisions, as 

they apply to Indian country units, will remain in the FIP. The full 

SIP will include those provisions only as they apply to non-Indian 

country units. 

As a practical matter, this means that the Indian country new 

unit set-aside provisions, which apply exclusively to Indian country 

new units, will remain entirely in the FIP. Further, other trading 

program provisions that reference both non-Indian country units and 

Indian country units (such as the applicability provisions) will 

remain in the FIP to the extent of their application to Indian 
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country units and will be included in the full SIP to the extent of 

their application to non-Indian country units. 

However, EPA notes that the assurance provisions in each 

Transport Rule trading program require calculations using the entire 

state budget, including any portion of the budget that may be 

allocated to Indian country new units. Further, EPA notes that 

currently no new units are planned or anticipated to be located in 

Indian country. Under these circumstances, EPA will handle the 

assurance provisions as follows. The full SIP for a state having 

Indian country will initially include the assurance provisions, as 

set forth in the FIP, except with removal of any references to 

sources and units in Indian country. The FIP will initially not 

include the assurance provisions, which will be fully effective and 

enforceable under the full SIP. In the event that any new unit is 

located in Indian country in the state, EPA intends to modify its 

approval of the full SIP to take back the assurance provisions in 

order to apply, in the FIP, the assurance provisions to both Indian 

country and non-Indian country units.

This final rule not only allows a state to choose to submit an 

abbreviated or a full SIP; it also allows a state to choose to submit 

either form of SIP to replace any or all of the FIPs in this rule as 

they apply to a particular state. By promulgating these Transport 

Rule FIPs, EPA in no way affects the right of a state to submit, for 

review and approval, a SIP that replaces the federal requirements of 

the FIP with state requirements that do not involve state 
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participation in the Transport Rule trading programs. In order to 

replace the FIP in a state, the state’s SIP taking an approach other 

than participation in Transport Rule trading programs must provide 

adequate provisions to prohibit NOX and SO2 emissions that are 

determined in the Transport Rule to contribute significantly to 

nonattainment or interfere with maintenance in another state or 

states. EPA will review such a SIP on a case-by-case basis. The 

Transport Rule FIPs remain fully in place in each covered state until 

a state’s SIP is submitted and approved by EPA to revise or replace a 

FIP.

In response to numerous comments urging EPA to allow states to 

determine allowance allocations as soon as possible, EPA has 

developed a SIP revision procedure that applies to 2013 allowance 

allocations only. In developing this procedure, EPA is balancing the 

desire to allow states the flexibility to tailor allowance 

allocations to the specific needs and situations in a particular 

state with the need to provide certainty to source owners and 

operators by having allowances recorded sufficiently ahead of the 

control period for which the allocations are made in order to 

facilitate owners’ and operators’ efforts to optimize their

compliance strategies. This final rule allows states to make 2013 

allowance allocations through the use of a SIP revision that is 

narrower in scope than the other SIP revisions states can use to 

replace the FIPs and/or to make allocation decisions for 2014 and 

beyond. For 2013 allocations, the scope of the SIP revision is 
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limited to allocations made to units that commence commercial 

operation before January 1, 2010 and provided in the form of a list 

of those units and their corresponding allocations for 2013. 

Additionally, this particular SIP revision may allocate only the 

portions of the state budgets set forth in Tables X-1 through X-3, 

i.e., each state budget minus the new unit set-aside and the Indian 

country new unit set-aside.

In developing this procedure, EPA set deadlines for submissions 

of the SIP revisions for 2013 allocations and for recordation of the 

allocations that balanced the need to record allowances sufficiently 

ahead of the control period with the desire to allow state 

flexibility for 2013. EPA set deadlines that will allow sufficient 

time for EPA to review and approve these SIP revisions, taking into 

account that EPA approval must be final and effective before the 2013 

allocations can be recorded and the allowances are available for 

trading. In order to ensure that EPA review and approval (which must 

include public notice and opportunity for comment) can be completed 

in time, the final rule necessarily limits the allowed scope of the 

SIP revisions for 2013 allocations, as set forth in the requirements 

discussed below, and thereby limits the issues that must be 

considered and addressed in the review and approval process. 

Further, the final rule prescribes the form in which the state 

allocations for 2013 must be provided to EPA in order to facilitate 

rapid recordation of the allocations upon their approval.
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States, along with their sources, will need to weigh the tradeoffs of a relatively short period of recording before the control 

period for which the allocation is made (about 6 months) with the 

desire to have state allocations in 2013, when deciding whether to 

pursue a SIP revision for 2013 allocations. States may choose to 

submit a SIP revision for one or more of the trading programs. In 

other words, state allocations for 2013 could apply in one trading 

program while 2013 FIP allocations apply in another.

States can make 2013 allowance allocations provided the state meets 

certain requirements.

 By the date 70 days after publication of the final rule in the 

Federal Register, a state must provide notification to EPA if 

the state intends to submit state allocations for 2013. The 

notification must be in a format prescribed by the Administrator 

and submitted electronically.

 By April 1, 2012, the state must submit a SIP revision to EPA 

that:

o Allocates to existing units123 only, provides a list of the 

units and their state allocations to EPA electronically and 

in a format prescribed by EPA, and does not provide for any 

change in the units and allocations on the list and in any 

allocation previously determined and recorded by the 

Administrator;

 

123 Existing unit means a unit that commenced commercial operation 

before January 1, 2010.
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o Allocates a total amount of allowances for 2013 that does 

not exceed the applicable amount in Tables X-1 through X-3

for each trading program that applies in that particular 

state; and

o Provides for no set-asides and does not alter the new unit 

set-asides, the Indian country new unit set-asides, and any 

aspect of the FIP rules other than the existing-unit 

allocations for 2013. 

If EPA does not receive notification from a state by the date 70 

days after publication of the final rule in the Federal Register, EPA 

will record FIP allocations for 2012 and 2013 as scheduled (by the 

date 90 days after publication of the final rule). If EPA receives 

timely notification from a state, EPA will record FIP allocations for 

2012 only and wait to record 2013 allocations. If the state provides 

a timely (not later than April 1, 2012) SIP revision meeting all the 

above-described requirements and EPA approves the SIP revision by 

October 1, 2012, EPA will record state-determined allocations for 

2013 by October 1, 2012. Otherwise, EPA will record the EPAdetermined allocations for 2013.

Table X-1 Portion of the Annual NOX Trading Budget Available for State 

Allocation in 2013

State Portion of the NOX Annual 

Trading Budget Available for 

State Allocation in 2013

Alabama 71,237

Georgia 60,770

Illinois 44,042

Indiana 106,434
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Iowa 37,568

Kansas 30,100

Kentucky 81,683

Maryland 16,300

Michigan 58,989

Minnesota 28,981

Missouri 50,803

Nebraska 24,589

New Jersey 7,121

New York 17,017

North Carolina 47,552

Ohio 90,849

Pennsylvania 117,586

South Carolina 31,848

Tennessee 34,989

Texas 129,587

Virginia 31,580

West Virginia 56,498

Wisconsin 29,730

Table X-2 Portion of the Ozone-Season NOX Trading Budget Available for 

State Allocation in 2013

State Portion of the Ozone Season NOX

Trading Budget Available for 

State Allocation in 2013

Alabama 31,111

Arkansas 14,736

Florida 27,268

Georgia 27,385

Illinois 19,511

Indiana 45,470

Kentucky 34,720

Louisiana 13,029

Maryland 7,035

Mississippi 9,957

New Jersey 3,314

New York 8,081

North Carolina 20,838

Ohio 39,262
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Pennsylvania 51,157

South Carolina 13,631

Tennessee 14,610

Texas 61,152

Virginia 13,729

West Virginia 24,019

Table X-3 Portion of the SO2 Group 1 or Group 2 Trading Budget 

Available for State Allocation in 2013

State Portion of the SO2 Group 1 or 

Group 2 Trading Budget 

Available for State Allocation 

in 2013

Alabama 211,712

Georgia 155,356

Illinois 223,145

Indiana 276,861

Iowa 104,943

Kansas 40,697

Kentucky 218,702

Maryland 29,518

Michigan 224,717

Minnesota 41,141

Missouri 203,317

Nebraska 62,450

New Jersey 5,463

New York 26,778

North Carolina 125,931

Ohio 304,025

Pennsylvania 273,078

South Carolina 86,848

Tennessee 145,187

Texas 231,756

Virginia 67,987

West Virginia 135,942

Wisconsin 75,506

EPA will work with states that wish to submit full SIPs or 

abbreviated SIPs to ensure a smooth integration with the relevant 
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Transport Rule trading programs. The Agency intends to provide 

information and tools to assist states in their rulemaking efforts, 

including electronic versions of the Transport Rule trading rules and 

other products states feel may be helpful. States that submit 

approvable full SIPs or abbreviated SIPs to implement one or all of 

the Transport Rule trading programs are not required to include an 

additional technical demonstration relating to elimination of 

emissions that contribute significantly to nonattainment or 

contribute to maintenance in downwind areas.

XI. Structure and Key Elements of Transport Rule Air Quality-Assured 

Trading Program Rules 

In order to make the final FIP trading program rules as simple 

and consistent as possible, EPA designed them so that the final rules 

(like the proposed rules) for each of the trading programs (i.e., the 

“TR NOX Annual Trading Program”, “TR NOX Ozone Season Trading 

Program”, “TR SO2 Group 1 Trading Program”, and “TR SO2 Group 2 

Trading Program”) are parallel in structure and contain the same 

basic elements. For example, the rules for the Transport Rule annual 

NOX, ozone-season NOX, SO2 Group 1, and SO2 Group 2 trading programs 

are located, respectively, in subparts AAAAA (§§97.401, et seq.), 

BBBBB (§§97.501, et seq.), CCCCC (§§97.601, et seq.), and DDDDD 

(§§97.701, et seq.) of Part 97 in Title 40 of the Code of Federal 

Regulations. Moreover, the order of the specific provisions for each 

trading program is the same, and the provisions have parallel 
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numbering. The key elements of the final Transport Rule trading 

program rules are as follows.

(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

Most of the definitions in the final Transport Rule trading 

program rules are essentially the same as in the proposed rules and 

for each of the Transport Rule trading programs (except where 

necessary to reflect the different pollutants (NOX and SO2), control 

periods (for annual and ozone-season NOX, and for annual SO2), and 

geographic coverage involved in the trading programs). Moreover, 

many of the definitions in the final rules that are essentially the 

same as in the proposed rule are also essentially the same as in 

prior EPA-administered trading programs. However, as discussed in 

more detail below, some of the definitions in the final rules 

clarify, or differ from, the definitions in the proposed rule. 

As noted, several definitions in the final rules are essentially 

the same as those both in the proposed rules and in prior EPAadministered trading programs. Examples include the definitions of 

“source,” “allowance transfer deadline,” “owner,” “operator”, 

“Allowance Management System” (used instead of the term “Allowance 

Tracking System”), and “continuous emission monitoring system.” 

One example of a definition in the final rules that is the same 

as in the proposed rule, but that clarifies the definition used in 

prior trading programs is the definition of “fossil fuel.” In the 
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final rule, the term “fossil fuel” is defined in general as including 

natural gas, petroleum, coal, or any form of fuel derived from such 

material, 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 are used as fuel, these materials in the 

consumer products qualify as fossil fuel. The definition in the 

final rules also includes language establishing a narrower meaning of 

“fossil fuel” that is not generally applicable, but rather is 

applicable only for purposes of applying the limitation on fossilfuel use under the solid waste incineration unit exemption (which is 

discussed elsewhere in this preamble). This latter portion of the 

“fossil fuel” definition makes explicit an interpretation that EPA 

adopted in CAIR that -- solely for purposes of applying the fossilfuel use limitation in that 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, applying this narrower meaning, consumer products made from 

natural gas, petroleum, or coal are not fossil fuel, for purposes of 

determining qualification under the fossil-fuel use limitation, 

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). 
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As noted above, some of definitions in the final rules clarify 

definitions in the proposed rules. The definitions of “allowable NOX

emission rate” and “allowable SO2 emission rate” are clarified by 

explaining that such a rate is the most stringent state or federal 

emission rate limitation, expressed in lb/MWhr or, if originally 

expressed in lb/mmBtu, converted to lb/MWhr by multiplying it by the 

unit’s heat rate in mmBtu/MWhr. This clarification ensures 

consistency from unit to unit in determining a unit’s allowable rate.

By further example, while the proposed rules used the same 

definition of “commence commercial operation” as in prior EPAadministered trading programs, the final rules clarify the 

definition. Under the definition in the proposed rules, a unit that 

is physically changed is treated as the same unit. However, the 

proposed rules were unclear about the treatment of a unit that is 

replaced and whether moving a unit to a different location or source 

constitutes a physical change. The definition of “commence 

commercial operation” in the final rules clarifies that a unit that 

is physically changed (which includes a unit that is replaced) 

continues to be treated, for purposes of this final rule, as the same 

unit with the same commence-commercial-operation date. The 

definition also clarifies that moving a unit to a different location 

or source is treated the same as a physical change, and so the unit 

continues to be treated as the same unit. The definition also 

clarifies that a unit (the replaced unit) that is replaced, whether 

at the same source or a different source, is treated as the same 
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unit, while the unit (the replacement unit) that replaces the unit is 

treated as a separate unit with a new commence-commercial-operation 

date. (The definition of “commence operation” is removed in the 

final rules because they do not use this term.)

By further example, while the proposed rules used the same 

definition of “unit” as in prior EPA-administered trading programs, 

the final rules clarify the definition. The “unit” definition is 

clarified by expanding it to incorporate explicitly the concepts –-

set forth in the definition in the final rules of “commence 

commercial operation” and thus already applicable to all units --

that a unit that is physically changed, moved to a different location 

or source, or replaced at the same or a different source continues to 

be treated as the same unit and that a replacement unit at the same 

source is treated as a separate unit. EPA believes that it is 

preferable to provide a comprehensive definition of “unit” in one 

place because the term is used so frequently in the final rules. 

By further example, the definition of “nameplate capacity” is 

clarified in the final rules by explaining that it is expressed in 

MWe rounded to the nearest tenth. This is the same rounding 

convention that is used in the reporting of nameplate capacity to the 

Energy Information Administration.

As noted above, some of the definitions in the final rules are 

similar to those in the proposed rules but have some substantive 

differences. For example, in the proposed rules, the definitions of 

“cogeneration unit” and “fossil-fuel-fired” are similar to those in 
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prior trading programs but with changes to minimize the need for data

concerning individual units or combustion devices for periods before 

1990. In order to qualify as fossil-fuel-fired, a unit would have to 

combust any amount of fossil fuel in 1990 or thereafter. In order to 

qualify as a cogeneration unit, a unit would have to meet certain 

efficiency and operating standards during the later of: the 12-month 

period starting when the unit begins producing electricity, or 1990. 

For a topping-cycle unit, 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 and useful thermal energy must 

be no less than a certain percentage of total energy output, and, for 

a bottoming-cycle unit, useful power must be no less than a certain 

percentage of total energy input. EPA proposed to limit to 1990 or 

later the historical period for which information on fuel consumption 

and on cogeneration unit efficiency and operations would be required 

to apply the “fossil-fuel-fired” and “cogeneration unit” definitions. 

This limitation was proposed because EPA was concerned that some 

owners and operators could have difficulty obtaining pre-1990 

information about older units, particularly for units whose ownership 

has changed over time. 

While EPA proposed to use 1990 as the earliest year for which 

information would be required under these definitions, EPA requested 

comment on whether a more recent year should be used. As discussed 

elsewhere in this preamble, the final rules use 2005 (about 5 years 

before this rule’s promulgation), rather than 1990, as the reference 
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year. Further, because the language describing the historical time 

period used (including the reference year), appeared in the proposal 

both in the “cogeneration unit” definition and the provisions 

concerning cogeneration units in the applicability provisions, the 

final rules removed any language about the historical time period 

from the “cogeneration unit” definition and revised the language in 

the applicability provisions to use the 2005 reference year for the 

requirements for meeting the exemption for cogeneration units from 

the Transport Rule trading programs. Further, consistent with this 

use of 2005 as the reference year, the “fossil-fuel-fired” definition 

in the final rule specifically references 2005, rather than 1990, and 

as discussed elsewhere in this preamble, the final rules also use 

January 1, 2005 (rather than November 15, 1990) as the reference date 

throughout the applicability provisions.

With this change in the reference date for the requirement to 

meet the operating and efficiency standards under the “cogeneration 

unit” definition, a unit would have to meet these standards 

throughout the later of 2005 or the 12–month period starting when the 

unit begins producing electricity and continuing thereafter. EPA 

requested comment on whether these standards should be applied to a 

calendar year when the unit involved did not combust any fuel, i.e., 

did not operate at all. As discussed elsewhere in this preamble, the 

final rules expressly provide that the operating and efficiency 

standards do not have to be met for a calendar year throughout which 

a unit did not operate at all.
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In addition, under the proposed rules, if a group of 

cogeneration units operating as an integrated cogeneration system met 

the efficiency standards, a topping-cycle unit in that system would 

be deemed to meet those standards. EPA requested comment on whether 

this provision should also apply to a bottoming-cycle unit. As 

discussed elsewhere in this preamble, this provision in the final 

rules is not limited to topping-cycle units.

By further example of definitions in the final rules that have 

substantive differences from the definitions in the proposed rules, 

the proposed definitions of “TR NOX Annual allowance,” “TR NOX Ozone 

Season allowance,” “TR SO2 Group 1 allowance,” “TR SO2 Group 1 

allowance,” “TR NOX Annual Trading Program,” “TR NOX Ozone Season 

Trading Program,” “TR SO2 Group 1 Trading Program,” and “TR SO2 Group 

1 Trading Program” are changed in the final rules. Language is added 

to the definitions in order to reference comparable allowances and 

trading programs established through SIP revisions submitted by 

states and approved by the Administrator. As discussed elsewhere in 

this preamble, the final Transport Rule provides that, if a state 

submits SIP revisions meeting certain specified requirements, the 

state or permitting authority (rather than the Administrator) will 

allocate allowances, and the covered sources in the state will 

participate -– along with covered sources in states remaining subject 

to the Transport Rule FIPs -- in an integrated, region-wide air 

quality-assured trading program under which both any allowance 

allocated by the Administrator and any allowance allocated by the 
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state or permitting authority will each authorize one ton of 

emissions of the relevant pollutant and will be usable by any source 

for compliance with the requirement to hold allowances covering 

emissions.

As noted above, the final rules include some definitions that 

were not used in prior EPA-administered trading programs and that 

reflect unique provisions of the Transport Rule trading programs. 

For example, the terms, “assurance account,” “TR NOX Annual unit,” “TR 

NOX Ozone Season unit,” “TR SO2 Group 1 unit,” “TR SO2 Group 2 unit,” 

“common designated representative,” “common designated 

representative’s assurance level,” and “common designated 

representative’s share” are used and defined in the final rule.

While the proposed rules included definitions for the terms, 

“owner’s assurance level” and “owner’s share”, the final rules 

replace these terms and instead define the terms, “common designated 

representative,” “common designated representative’s assurance 

level,” and “common designated representative’s share.” This is 

because, as discussed elsewhere in this preamble, the final rules 

include assurance provisions similar to those in the proposed rules 

but that are implemented based on groups of units having a common 

designated representative, instead of being implemented on an ownerby-owner basis. The definition of “common designated representative” 

in the final rules reflects that the determination of what groups of 

units and sources in a State have a common designated representative 

is made based on the identity of units’ and sources’ designated 
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representatives as of April 1 of the year after the year of the 

control period when a state triggers the assurance provisions. EPA 

believes that the use of this reference date will give owners and 

operators greater flexibility to select common designated 

representatives after information about total state control period 

emissions is available and after the allowance transfer deadline when 

owners and operators may prefer to have a designated representative 

for their specific source (rather than a common designated 

representative for a larger group) who is focused on ensuring that 

sufficient allowances are held in or transferred to the source’s 

account to cover the sources’ emissions. EPA notes that the 

definition of “common designated representative’s share” is simpler 

than the definition of “owner’s share” because implementing the 

assurance provisions at the designated representative level means it 

is no longer necessary to address, in the definition, owner- and 

unit-level issues that may arise when a unit has multiple owners or 

where two or more units emit through the same stack.

Finally, some definitions are added to the final rules that are 

not in the proposed rules. For example, because the term, “business 

day,” was used, but not defined, in the proposed rule, its meaning 

was unclear. Specifically, it was unclear whether a day that was 

uniquely a state holiday, and not a federal holiday, was a business 

day for purposes of the federally administered Transport Rule trading 

programs, e.g., whether the allowance transfer deadline applicable to 

all sources in all states in a Transport Rule trading program could 
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fall on a day that was a unique state holiday in one or a few states 

or whether the allowance transfer deadline would be advanced to the 

next business day for all sources in all states or perhaps only for 

sources in the state with the state holiday. EPA believes that, for 

a federally administered trading program covering sources in multiple 

states, the deadlines should be clear and uniform for all sources, 

regardless of the state in which the sources are located, and should 

not be affected by unique state holidays of which owners and 

operators of sources in other states may not even be aware. 

Consequently, the “business day” definition is added in the final 

rules and means a day that does not fall on a weekend or a federal 

holiday. 

By further example, a definition for “natural gas” was added in 

the final rules. That definition, as well as the definition for 

“coal,” incorporate the corresponding definitions in Part 72 of the 

Acid Rain Program regulations. The Part 72 definitions are 

incorporated because they are also used in the Part 75 monitoring, 

reporting, and recordkeeping provisions, which provisions are already 

incorporated in the final Transport Rule Trading Program rules. 

(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 in the final rules are, except as 

discussed herein, essentially the same as in the proposed rules and 

for each of the Transport Rule trading programs. Of course, for each 

trading program, the definition of “State” reflects differences in 
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the specific states whose electric generating units are covered by 

the respective trading program. 

Under the general applicability provisions of the proposed 

rules, the Transport Rule trading programs would cover fossil-fuelfired boilers and combustion turbines serving –- at any time starting 

November 15, 1990 or later -- 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. As discussed elsewhere in this preamble, the 

general applicability provisions in the final rules reference January 

1, 2005 (about 5 years before this rule’s promulgation), rather than 

November 15, 1990. 

Cogeneration unit exemption. Under the final rules (as well as 

the proposed rules) certain cogeneration units or solid waste 

incinerators otherwise covered by the general category of covered 

units are exempt from the FIP requirements. In particular, the final 

rules include an exemption for a unit that qualifies as a 

cogeneration unit throughout the later of 2005 or the first 12 months 

during which the unit first produces electricity and continues to 

qualify throughout each calendar year ending after the later of 2005 

or such 12-month period and that meets the limitation on electricity 

sales to the grid. In order to qualify as a cogeneration unit 

(i.e., meet the definition of “cogeneration unit”) in the final 

rules, a unit (i.e., a boiler or combustion turbine) must operate as 

part of a “cogeneration system,” which is defined as an integrated 
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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 

addition, in order to qualify, a unit must be a topping-cycle unit or 

a bottoming cycle unit because units that produce useful thermal 

energy and useful power through sequential use of energy either 

produce useful power first (i.e., are topping-cycle units) or produce 

thermal energy first (i.e., are bottom-cycle units).

Further, in order to qualify as a cogeneration unit, a unit also 

must meet, on a 12-month or annual basis, the above described 

efficiency and operating standards. As discussed elsewhere in this 

preamble, EPA clarifies that the electricity sales limitation under 

the exemption is applied in the same way whether a unit serves only 

one generator or serves more than one generator. In both cases, the 

total amount of electricity produced annually by a unit and sold to 

the grid cannot exceed the greater of one-third of the unit’s 

potential electric output capacity or 219,000 MWhr.

The final rules also clarify when a unit that meets the 

requirements for the cogeneration unit exemption and subsequently 

fails to meet all these requirements loses the exemption and becomes 

a covered unit. Such a unit loses the exemption starting the earlier 

of January 1 (or May 1 for the NOX ozone season trading program) after 

the first year during which the unit no longer meets the 

“cogeneration unit” definition or January 1 (or May 1) of the first 
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year during which the unit no longer meets the electricity sales 

limitation.

Solid waste incineration unit exemption. The final rules also 

include an exemption for a unit that qualifies as a solid waste 

incineration unit during the later of 2005 or the first 12 months 

during which the unit first produces electricity, that continues to 

qualify throughout each calendar year ending after the later of 2005 

or such 12-month period, and that meets the limitation on fossil-fuel 

use. In contrast, the exemption for solid waste incineration units 

in the proposed rules distinguished between units commencing 

operation before January 1, 1985 and those commencing operation on or 

after that date and established somewhat different criteria for these 

two categories of units. As discussed elsewhere in this preamble, 

the final rules remove the distinction based on whether a solid waste 

incineration unit commences operation before January 1, 1985 or on or 

after January 1, 1985. In order to be exempt, the unit must qualify 

as a solid waste incineration units during the later of 2005 or the 

first 12 months during which the unit first produces electricity, 

must continue to qualify throughout each calendar year ending after 

the later of 2005 or such 12-month period, and must meet the 

limitation on fossil-fuel use on a three-year average basis during 

the first 3 years of operation starting no earlier than 2005 and 

every 3 years of operation thereafter.

Retired unit exemption. The final rule provisions exempting 

permanently retired units from most of the requirements of the 
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Transport Rule trading programs are essentially the same as in the 

proposed rules and for each of the Transport Rule trading programs. 

The retired unit provisions exempt these units from the requirements 

for emission monitoring, recordkeeping, and reporting and for holding 

allowances, as of the allowance transfer deadline, sufficient to 

cover their emissions. However, the permanently retired units in a 

state must be included in determining whether owners and operators 

must surrender allowances, and, if so, how many, to comply with the 

assurance provisions (which are discussed elsewhere in this preamble) 

if the state’s total covered-unit emissions exceed the state 

assurance level. 

Specifically, a common designated representative must include 

these units in determining whether his or her share of total 

emissions of covered units in a state exceed his or her share 

(generally based on the allowances allocated to the units that he or 

she represents) of the state trading budget with the variability 

limit and thus whether the owners and operators of the units that he 

or she represents have to surrender allowances under the assurance 

provisions.

(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 Transport Rule trading programs and 

presented as standard requirements in the final rules are, except as 

discussed herein, essentially the same as in proposed rules and for 

each of the Transport Rule trading programs. These basic 
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requirements 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 CAA provisions. 

In particular, the paragraphs addressing emissions requirements 

for owners and operators describe these requirements in detail and 

reference other sections of the final rules that set forth the 

procedures for determining compliance with the emissions limitations 

and assurance provisions. The paragraphs in the final rules 

concerning compliance with the emissions limitations clarify that 

owners and operators of a source and each covered unit at the source 

must hold allowances at least equaling the total control period 

emissions of all covered units at the source. Further, the 

paragraphs in the final rules concerning compliance with the 

assurance provisions differ from those in the proposed rules in that, 

as discussed elsewhere in this preamble, the final rules implement 

the assurance provisions based on groups of units with a common 

designated representative, instead of being implemented on an ownerby-owner basis, as proposed. Under the final rules, the assurance 

provisions are triggered when total control period emissions by 

covered units in a state (starting in 2012) exceed the state trading 

budget plus variability limit. If the assurance provisions are 
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triggered for a state for a control period in a given year, owners’ 

and operators’ responsibility for the resulting penalty (i.e., the 

surrender of allowances for deduction through the transfer of such 

allowances to the assurance account created by the Administrator for 

such owners and operators) is determined on a common designated 

representative basis. 

For purposes of implementing the assurance provisions, covered 

units in a state are in effect grouped by common designated 

representative (which is defined as an individual (i.e., a natural 

person) who is the designated representative, as distinguished from 

the alternate designated representative, for a group of one or more 

units and sources as of April 1 after the control period for which 

the state exceeds the state assurance level). The control period 

emissions of all covered units with a common designated 

representative are compared with the allowance allocations of such 

units plus their share of the state variability limit. The owners 

and operators of the units and sources in each group that has 

emissions in excess of allocations plus share of variability are 

subject to the assurance provisions penalty. The owners and 

operators of the units and sources in each group must transfer to the 

assurance account created for such owners and operators a total 

amount of allowances equal to two times such owners’ and operators’ 

proportionate share of the state’s excess of covered-unit emissions 

over the state trading budget plus variability.
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The group’s proportionate share is the percentage resulting from 

division of the amount of the group’s excess of emissions over 

allocations plus share of variability by the sum of these excess 

amounts for all groups of units with a common designated 

representative in the state. The final rule makes it clear that this 

percentage is not rounded to the nearest whole number, but rather 

that the calculated amount of allowances resulting from application 

of this percentage is rounded to the nearest whole number because, in 

the Transport Rule trading programs, only whole (not fractional) 

allowances are used. If instead this percentage were rounded before 

its application, each group’s share would be either 100 percent or 0 

percent, which would be contrary to the intent of the assurance 

provisions in both the final rules and the proposed rules. 

The provisions addressing the assurance requirements in the 

final rules reflect this common-designated-representative-based 

approach. For example, as discussed elsewhere in this preamble, 

these provisions use the terms, “common designated representative’s 

share” and “common designated representative’s assurance level,” in 

lieu of the terms, “owner’s share” and “owner’s assurance level,” 

used in the proposed rules. By further example, these final rule 

provisions refer to both “common designated representatives” and 

“owners and operators,” rather than simply “owners.”

The final rules also explain what vintage year (i.e., allocation 

year) of allowances can be used in order to comply with the 

requirement to cover emissions and with the requirements of the 
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assurance provisions. With regard to emissions during a control 

period in a given year, only allowances allocated for that year or 

any prior year can be used to cover such emissions. Further, only 

allowances of the following vintage can be used to meet excess 

emissions penalties and assurance penalties concerning emissions 

during a control period in a given year: allowances allocated for 

that year, any year before that year, or the year immediately after 

that year. This approach makes the vintage years usable for excess 

emissions and assurance penalties consistent and helps ensure that 

allowances will be available to meet these obligations.

The final rules also clarify the standard emission requirements 

by explaining further what is meant by the provision that an 

allowance is a limited authorization to emit. The final rules 

clarify that an allowance provides authorization to emit during the 

control period in one year and is limited in both its use and its 

duration. For example, each Transport Rule trading program’s final 

rules state that an allowance provides an emission authorization that 

can only be used in accordance with the requirements of the 

respective trading program, such as the requirements specifying what 

allowances are available for use, and how such allowances must be 

held or transferred, in order to cover emissions or meet the 

assurance provisions. By further example, under the final rules, an 

allowance continues to provide an authorization to emit one ton of 

the relevant pollutant until the allowance is deducted, e.g., in 

order to be used for compliance with the requirement to cover 
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emissions or the requirements of the assurance provisions. Moreover, 

under the final rules, the Administrator has the express authority to 

terminate or limit the authorization to emit, and thereby change the 

use and duration of the authorization, described in the final rules, 

to the extent he or she determines to be necessary or appropriate to 

implement any provision of the CAA.

The remaining paragraphs in the standard requirements section 

address permitting, recordkeeping and reporting, liability 

provisions, and the effect on other CAA provisions. For example, the 

paragraphs concerning permitting requirements are limited to stating 

that no title V permit revisions are necessary to account for 

allowance allocation, holding, deduction, or transfer and that the 

minor permit modification procedures can 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. 

These provisions remain essentially the same in the final rules as in 

the proposed rules.

(iv) §§96.407, 97.507, 97.607, and 97.707 -- Computation of Time

These sections address how to determine the deadlines referenced 

in the Transport Rule trading program rules and are, except as 

discussed herein, essentially the same as in the proposed rules and 

for each of the Transport Rule trading programs. The final rules 

revise the proposed rule provisions concerning the treatment of the 

final date in any time period in order to make the provision 

consistent with the approach discussed above with regard to the new 
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definition of “business day.” The revised provision states that, if 

the final date is not a “business day”, then the time period is 

extended to the next “business day.” 

(v) §§97.408, 97.508, 97.608, 97.708 and Part 78 -- Administrative 

Appeal Procedures

Under the final Transport Rule, final decisions of the 

Administrator under the Transport Rule trading programs are 

appealable to EPA’s Environmental Appeals Board under the regulations 

set forth in Part 78 (40 CFR part 78), which are revised by the final 

Transport Rule to accommodate such appeals. The provisions in the 

final Transport Rule concerning appeals are, except as discussed 

herein, essentially the same as in the proposed Transport Rule. The 

proposed Transport Rule would add a provision in Part 78 explaining 

who is an “interested person” with regard to a decision, i.e., a 

person who submitted comments, testimony, or objections as part of 

the process of making the decision or a person who submitted his or 

her name to the Administrator to be placed to an interested persons 

list. The final Transport Rule includes that provision, but with 

additional language that clarifies the process for submitting a name 

to be placed on such a list. 

(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 set forth: certain 

information related to allowance allocation and for implementation of 

the assurance provisions; the timing for allocation of allowances to 
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existing and new units; and the procedures for new unit allocations. 

In particular, these sections include tables providing, for each 

state covered by the particular Transport Rule trading program and 

for each year, the state trading budget (without the variability 

limit), new unit set-aside, Indian country new unit set-aside (where 

applicable), and variability limit. These provisions in the final 

rules differ in several ways, from the proposed rules and are 

essentially the same for each of the Transport Rule trading programs.

With regard to the tables in the final rules for the state 

trading budgets (without the variability limits), new unit setasides, and variability limits, the identity of the specific states 

involved and the values for each state differ from the tables in the 

proposed rules. The final rule values reflect the determinations and 

modeling underlying the final rules and discussed elsewhere in this 

preamble. Further, as discussed elsewhere in this preamble, the 

variability limits are only those based on one-year variability and 

not those proposed to be based on three-year variability, and Indian 

country set-asides are shown for states with Indian country within 

their borders.

With regard to existing unit allocations, the final rules 

provide that these allocations will be set forth in a notice of data 

availability to be issued by the Administrator. In contrast, the 

proposed rules stated that existing unit allocations would be set 

forth in an appendix to the rules for each Transport Rule trading 

program. EPA believes that including these allocations in a notice 
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of data availability referencing the EPA website (rather than 

publishing them in tables requiring a large number of pages in the 

Federal Register for each Transport Rule trading program) is a more 

efficient method of making these allocations public, particularly 

since these allocations may be changed for 2013 and thereafter by 

states through SIP revisions. In addition, under the final rules the 

allocations for an existing unit can change if the unit does not 

operate (i.e., has no heat input) for 2 consecutive years starting in 

2012. In that case, the unit continues to receive its existing unit 

allocation for those years plus only 2 more years. As explained 

elsewhere in this preamble, this is a modification of the proposed 

rules, under which a unit that did not operate for 3 consecutive 

years would continue to receive its existing unit allocation for 

those years plus 3 more years. 

Under the final rule provisions for new units, the Administrator 

allocates allowances from the new unit set-aside for the state where 

the respective unit is located and for each year when the unit first 

becomes eligible for an allocation and each year thereafter. The 

units eligible for new unit set-aside allocations include units 

commencing commercial operation on or after January 1, 2010, as well 

as several other categories of units, such as, for example, existing 

units that were not initially but then become covered units, existing 

units whose allocations are lost due to lack of unit operation and 

that subsequently begin operating again, and units that lost their 

allocations because they changed location from one state to another. 
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The approach in the final rules differs from the proposed rules, 

which required that owners and operators initially request allowances 

from the new unit set-aside when the unit first became eligible for 

an allocation. As discussed elsewhere in this preamble, under the 

final rules, EPA identifies which units become eligible and when they 

become eligible, based on information provided in other submissions 

(e.g., certificates of representation, monitoring system 

certifications, and quarterly emissions reports) that such units must 

make to EPA, and the requirement that owners and operators submit 

requests for new unit set-aside allocations is removed in the final 

rules.

The final rules also provide for two rounds of allocations from 

the new unit set-aside, in contrast with the proposed rules that 

provided for only one round. In the first round in the final rules 

(as in the single round in the proposed rules), a unit’s new unit 

set-aside allocation initially equals that unit’s emissions –- as 

determined in accordance with §§97.430-97.435, 97.530-97.535, 97.630-

97.635, and 97.730-97.735 of the final rules and 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. 

If the new unit set-aside lacks sufficient allowances to provide this 

initial allocation for all of the new units, then each new unit is 

allocated its proportionate share (based on its initial allocation 

amount) of the allowances in the new unit set-aside. The 

Administrator issues a notice of data availability informing the 
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public of the specific new unit allocations and provides an 

opportunity for submission of objections on the grounds that the 

allocations are not consistent with the requirements of the relevant 

final rule provisions. A second notice of data availability is 

subsequently issued in order to make any necessary corrections in the 

specific new unit allocations. As discussed elsewhere in this 

preamble, the final rules establish a somewhat different schedule for 

issuance of these notices of data availability than the proposed 

rules. In particular, a single set of dates (i.e., for the first 

notice, June 1 of the year for which the new unit allocations are 

described in the notice and, for the second notice, August 1 of that 

year) is established for all of the Transport Rule trading programs. 

For the reasons discussed elsewhere in this preamble, the final rules 

provide for a second round of allocations to the extent that any 

allowances remain in the new unit set-aside after the allocations are 

made to new units in the first round. (In the proposed rules, 

remaining allowances were immediately allocated to existing units.) 

The units eligible for allocations in the second round are new units 

that commenced commercial operation during the control period for 

which allocations are being made and during the prior control period. 

The second round allocation for each such unit initially equals the 

positive difference (if any) between the unit’s first round 

allocation (if any) and the unit’s emissions during the control 

period for which allocations are being made. If the amount of

allowances remaining in the new unit set-aside after the first round 
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is insufficient to provide this initial allocation for all of the 

second round new units, then each such new unit is allocated its 

proportionate share of the allowances remaining in the new unit setaside. The Administrator uses notices of data availability (which 

are issued by December 15 (for the annual trading programs) and 

September 15 (for the ozone season trading program) of the control 

period involved and February 15 (for the annual trading programs) and 

November 15 (for the ozone season trading program) before the 

allowance transfer deadline for the control period involved, in a 

manner analogous to the use of such notices in the first round, to 

inform the public about the identification of the new units in the 

second round allocations and obtain and consider any objections. The 

February 15 and November 15 notices also inform the public about the 

amounts of the second round allocations. If, after both rounds of 

allocations, any allowances remain in the new unit set-aside, those 

allowances are allocated to existing units in proportion to such 

units’ allocations.

The final rules also establish a separate Indian country new 

unit set-aside in each state where Indian country is located (i.e., 

in Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, 

Mississippi, Nebraska, New York, North Carolina, South Carolina, 

Texas, and Wisconsin). As discussed elsewhere in this preamble, the 

Administrator operates the Indian country new unit set-aside in 

essentially the same manner as state new unit set-aside, except that 

unallocated allowances remaining in the Indian country new unit set-
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aside after the two rounds of new unit set-aside allocations are 

first placed in the new unit set-aside in the state where the Indian 

country involved is located and then, if still unallocated, are 

allocated to existing units in the state. As with the state new unit 

set-aside, EPA will identify the new units qualifying for the Indian 

country new unit set-aside, calculate the allocations, and issue 

notices of data availability using the same schedules as notices for 

the state new unit set-aside. 

Under the final rules (like under the proposed rules), if a unit 

in certain specified categories is allocated allowances that should 

not have received them, the Administrator applies procedures under 

which the allocation is not recorded or the amount of the recorded 

allocations is deducted as an incorrect allocation, with one 

exception. The exception is where the determination of compliance 

with the emissions limitation (i.e., requirement to hold allowances 

covering emissions, as distinguished from the assurance provisions) 

for the source that includes the unit has already been completed, in 

which case no action is taken to account for the erroneous allocation 

for the control period involved.

While this procedure concerning recordation or deduction of 

allocations is the same as under the proposed rules, the final rules 

change the description of the circumstances under which this 

procedure concerning recordation or deduction of allocations is 

applied. Under both the final rules and the proposed rules, this 

procedure is applied to a unit (whether an existing unit or a new 
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unit) that receives an allocation but is not actually a covered unit. 

However, under the final rules, another category of units -- i.e., 

any existing unit that is not located –- as of January 1 of the 

control period for which the allocation is received -– in the state 

from whose trading budget the allocation was made is also subject to 

this procedure. Although relatively few units are moved from one 

state to another, EPA believes that it is important to address what 

happens to such units’ allocations, both because each state has a 

limited trading budget out of which all allocations for a year to 

existing and new units in that state must be made and because, under 

the assurance provisions, determinations are made about owners’ and 

operators’ surrender of allowances based on, among other things, the 

allocations for units in a specific state. Because, under the final 

rules, a unit that is moved from one state to another may lose its 

existing unit allocation in the first state under the above-described 

procedure, the final rules also makes such a unit eligible for 

allocations from the new-unit set-aside of the second state.

Finally, the final rules remove, as no longer necessary, one 

category of units that the proposed rules included as subject to this 

procedure. The proposed rules, treated, as existing units, some

units that had not yet operated but were projected to operate by 

January 1, 2012, and so the proposed rules made these units subject 

to the procedure for not recording or for deducting allocations if 

they actually were not required to certify their monitoring systems 

and hold allowances covering emissions starting January 1, 2012. The 
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final rule does not treat projected units as existing units and so 

this category of units no longer needs to be made subject to this 

procedure.

(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 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 also describe the designated representative’s and alternate 

designated representative’s responsibilities and the process through 

which he or she can delegate to an agent the authority to make 

electronic submissions to the Administrator. Except as discussed 

herein, the provisions in the final rules are essentially the same as 

in the proposed rules and for each of the Transport Rule trading 

programs.

The designated representative is the individual (i.e., the 

natural person) 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. One alternate designated representative 

(also an individual) can be selected to act on behalf of, and legally 

bind, the designated representative and thus the owners and 
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operators. Because the actions of the designated representative and 

alternate legally bind the owners and operators, the designated 

representative and alternate must submit a certificate of 

representation certifying that each was selected by an agreement 

binding on all such owners and operators and is authorized to act on 

their behalf. 

In the final rules (like in the proposed rules), the certificate 

of representation must contain: specified identifying information for 

the covered source (including location) and the 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. The final rules require an additional 

piece of identifying information, i.e., whether the unit is located 

in Indian country. This is necessary in order for the Administrator 

to implement the above-described Indian country new unit set-aside. 

All submissions (e.g., monitoring plans, monitoring system 

certifications, and allowance transfers) under the final rules for a 

covered source or covered unit must be submitted, signed, and 

certified by the designated representative or alternate, except that 

electronic submission may be delegated. 

In order to change the designated representative or alternate, a 

new certificate of representation must be received by the 

Administrator. A new certificate of representation must also be 

submitted to reflect changes in the owners and operators of the 
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source and units involved. The new certificate must be submitted 

within 30 days of such changes.

The final rules make explicit an implied requirement of the 

proposed rules, i.e., that, if a unit is added to a source or is 

moved from one source to a second source, a certificate of 

representation needs to be submitted to reflect the change. This 

requirement is implicit in the proposed rules when a unit is added to 

a source because the designated representative would not be 

authorized to make submissions concerning the added unit unless that 

unit were included on the certificate of representation. Similarly, 

where a unit is moved to another source, new certificates of 

representation would need to be submitted in order for the correct 

designated representative to be authorized to make submissions 

concerning the moved unit. Moreover, because compliance accounts in 

the Allowance Management System would cover all units at a given 

source and would be based on the information in the certificate of 

representation submitted by the designated representative for the 

source, when a unit is moved from a source to a second source, the 

designated representative of the second source would need to submit a 

certificate of representation removing the moved unit from the list 

of units.

The final rules explicitly require that a new certificate of 

representation be submitted to reflect changes (whether caused by the 

addition or removal of units) in which units are located at a source. 

In addition, the final rules impose a deadline on the submission 
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requirement of 30 days from the date of the change in the units. 

This is analogous to the maximum time period between a change in a 

unit’s owner or operator and the deadline for submission of a new 

certificate of representative reflecting to the change. Long before 

any actual move of a unit to a new location, owners and operators 

will need to make decisions about, and plan the implementation of, 

such a move. Consequently, EPA believes that a 30-day deadline after 

any move for reflecting the move in the certificate of representation 

is reasonable. In the event the change involves the addition of a 

unit that operated before being located at the source, the final 

Transport Rule also requires that the designated representative 

provide in the certificate of representation information on the 

entity from which the unit was obtained, the date on which the unit 

was obtained, and the date on which the unit became located at the 

source. In the event of a change involving the removal of a unit, 

the designated representative must provide in the certificate of 

representation information on the entity that obtained the unit, the 

date on which that entity obtained the unit, and the date on which 

the unit became no longer located at the source. This information 

will enable the Administrator to determine what actions are necessary 

to reflect the change in units located at the sources involved. For 

example, if a covered unit is moved from one source to second source, 

the Administrator will have the information necessary to determine 

whether the unit’s allocation should be changed to reflect movement 

of the unit from one state to another. 
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(4) Allowance Management System

Sections 97.420 through 97.428, 97.520 through 97.528, 97.620 

through 97.628, and 97.720 through 97.728 establish the procedures 

and requirements for using and operating the Allowance Management 

System (which is the electronic data system through which the 

Administrator handles 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 also provides 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. Except as discussed herein, these sections 

of the final rules are essentially the same as in the proposed rules 

and for each of the Transport Rule trading programs.

(i) §§97.420, 97.520, 97.620, and 97.720 –- Compliance, Assurance, 

and General Accounts

Under the final rules, the Allowance Management System contains 

three types of accounts. One type comprises compliance accounts, one 

of which the Administrator establishes for each covered source upon 

receipt of the certificate of representation for the source. A 

compliance account is the account in which all allowance allocations 

must be recorded and in which any allowances used by the covered 

source for compliance with the emission limitations must be held. 

The designated representative and alternate for the source are also 
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the authorized account representative and alternate for the 

compliance account. 

A second type comprises general accounts, which can be 

established by any entity upon receipt by the Administrator of an 

application for a general account. General accounts can be used by 

any person or group for holding or trading allowances. To open a 

general account, a person or group must submit an application for a 

general account, which is similar in many ways to a certificate of 

representation. The provisions for changing the authorized account 

representative and alternate, for submitting a superseding 

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 are analogous to those 

applicable to comparable matters for designated representatives and 

alternates.

A third type comprises assurance accounts. The Administrator 

establishes one assurance account for each group of units having a 

common designated representative and located in a state where the 

assurance provisions are triggered by total emissions exceeding the 

state trading budget plus variability.

(ii) §§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

Under the final rules, by [INSERT DATE 90 DAYS FROM DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], the Administrator must record 
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allowance allocations for existing units, as set forth in a required 

notice of data availability, for the Transport Rule annual NOX, ozoneseason NOX, and SO2 trading programs for 2012 and 2013, unless, as 

discussed elsewhere in this preamble, a state notifies the 

Administrator that the state will submit a SIP revision with 

existing-unit allocations for 2013 by May 1, 2012. If the 

Administrator approves that SIP revision by October 1, 2012, the 

Administrator will record the state-determined existing-unit 

allocations for 2013, and, in the absence of such approval by that 

date, the Administrator will record the EPA-determined existing-unit 

allocations for 2013. By July 1, 2013, the Administrator must record 

existing-unit allowance allocations (whether EPA- or statedetermined) for each Transport Rule trading program for 2014 and 

2015. By July 1, 2014, the Administrator must record existing-unit 

allowance allocations for each Transport Rule trading program for 

2016 and 2017. By July 1, 2015, the Administrator must record 

existing-unit allowance allocations for each Transport Rule trading 

program for 2018 and 2019. By July 1, 2016 and July 1 of each year 

thereafter, the Administrator must record existing-unit allowance 

allocations for each Transport Rule trading program for the control 

period in the fourth year after the year of the applicable 

recordation deadline. By August 1, 2012 and August 1 of each year 

thereafter, the Administrator must record new-unit allowance 

allocations for each Transport Rule trading program for that year. 
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These recordation deadlines differ from those in the proposed rules 

for two reasons. First, as discussed elsewhere in this preamble, EPA 

is adopting provisions that allow states to submit, and EPA to 

approve, SIP revisions (abbreviated or full SIPs) under which the 

state, rather than the Administrator, determines the distribution of 

allowances under one or more of the Transport Rule trading programs 

applicable in the state. In selecting allocation recordation 

deadlines, EPA took into account and balanced certain countervailing 

factors. On one hand, EPA considered the need to provide a 

reasonable time for a state to develop, propose, and finalize, and 

for EPA to review and propose and finalize approval of, the SIP 

revision and the desirability of providing a reasonable opportunity 

for state distributions to become effective for a year relatively 

soon after the 2012 commencement of the Transport Rule trading 

programs. EPA’s experience with prior trading programs has shown 

that the process for development and submission of SIP revisions by 

states and approval by EPA in many cases is about 18 months and in 

some cases even longer. On the other hand, EPA considered the 

desirability of owners and operators having allocations in their 

compliance accounts a reasonable time before the year for which the 

allocations are made (i.e., the vintage year). Having the 

allocations recorded, to the extent possible, before the vintage year 

facilitates compliance decisions and use of the allowance market in 

implementing such decisions. EPA believes that optimally allocations 

would be recorded at least 3 years in advance of the vintage year.
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In balancing these countervailing factors, EPA is adopting an 

allocation recordation schedule that provides initially for 

recordation ranging from 6 months to 18 months before the beginning 

of the control period in the first 2 years (i.e., 2012 and 2013) for 

which allocations are made and that, as allocations for control 

periods in subsequent years are recorded, gradually increases the 

amount of time between recordation and the beginning of the year of 

the control period involved until allocations are recorded about 

three and one-half years in advance. With regard to the need to 

facilitate states’ distribution of allowances, this approach gives 

states multiple opportunities to develop, submit, and obtain EPA 

approval for SIPs under which the states (rather than EPA) will 

distribute allowances under the Transport Rule trading programs for 

control periods relatively early in the programs. Because of time 

(which has in the past ranged from about 6 months to about 2 years) 

it may take for a state to develop and submit such a SIP and because 

of the time (which has in the past been at least 6 months) it will 

likely take EPA to review and approve such a SIP, EPA believes that 

2013 is the first year for which a state can determine allowance 

distributions and have them recorded some minimal time before the 

control period involved. With regard to the need to record 

allowances in advance, this approach achieves recordation at least 6 

months in advance and eventually achieves recordation by what EPA 

believes is an optimal amount of time (greater than 3 years) before 

the control period for which recorded allowances are issued. 
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As discussed elsewhere in this preamble, the approach to 

allowance recordation in the final rules results in following 

schedule for submission of abbreviated or full SIPs under the final 

Transport Rule. SIP revisions with existing-unit allocations for 

2013 control periods must be submitted to the Administrator by April 

1, 2012. Complete abbreviated and full SIPs must be submitted to the 

Administrator by: December 1, 2012 in order to govern allowance 

allocation and auction for control periods in 2014 and 2015; December 

1, 2013 in order to govern control periods in 2016 and 2017; December 

1, 2014 in order to govern allowance allocation and auction for 

control periods in 2018 and 2019; and December 1, 2015 and by January 

1 of any year thereafter in order to govern allowance allocation and 

auction for control periods in the fifth year after the year of such 

submission deadline.

The second reason for the differences in the recordation 

deadlines in the final rules, as compared to the proposed rules, is 

that, in order to simplify the recordation schedule for owners and 

operators and EPA, EPA set uniform recordation deadlines for all of 

the Transport Rule trading programs. EPA believes that these 

deadlines provide the Agency sufficient time, after receipt of any 

information necessary to determine allocations (e.g., for new unit 

set-aside allocations, the emission data from the control period in 

the prior year), to complete the recordation of allocations and, as 

discussed above, makes the allocations available to owners and 

operators before the year for which the allocations are made. EPA 
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notes that these are deadlines and that the Administrator has the 

discretion, where feasible and appropriate, to record allocations 

before such deadlines. 

 Under the final rules (as under the proposed rules), the process 

for transferring allowances from one account to another is quite 

simple. A transfer is 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 is 

submitted to the Administrator and, when the Administrator attempts 

to record the transfer, the transferor account includes the 

allowances identified in the form, the Administrator records 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.

(iii) §§97.424, 97.524, 97.624, and 97.724 –- Compliance with 

Emissions Limitations

Under the final rules (as under the proposed rules), 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 ozone-season 

NOX trading program), covered sources have a window of opportunity --

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 
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emissions and obtain any allowances that they need to cover their 

emissions during that control period. Each allowance issued in each 

Transport Rule trading program authorizes emission of one ton of the 

pollutant involved, and so is usable for compliance in that trading 

program, for a control period in the year for which the allowance was 

allocated or a later year. Consequently, each source needs –- as of 

the allowance transfer deadline –- to have in its compliance account, 

or properly submit a transfer that moves into its compliance account, 

enough allowances usable for compliance to authorize the source’s 

total emissions for the control period. 

If a source fails to hold sufficient allowances for 

compliance to cover the emissions, then the owners and operators must 

provide, for deduction by the Administrator, two allowances allocated 

for the control period, in the year of when the emissions occurred, 

any prior year, or the year immediately after the year of the 

emissions, for every allowance that the owners and operators failed 

to hold as required to cover emissions. In addition, the owners and 

operators are subject to discretionary civil penalties for each 

violation. 

(iv) §§97.425, 97.525, 97.625, and 97.725 –- Compliance with 

Assurance Provisions.

Under the final rules (as under the proposed rules), the 

assurance provisions ensure that each state will eliminate its 

significant contribution to nonattainment and interference with 

maintenance that EPA identifies in this action. A requirement that 
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owners and operators surrender allowances under the assurance 

provisions is triggered only for certain owners and operators of 

sources and units in a state where the total state covered-unit 

emissions for a control period exceed the applicable state trading 

budget with the variability limit. Moreover, the surrender 

requirement is implemented based on groups of sources and units with 

a common designated representative. For each group of sources and

units with a common designated representative, the owners and 

operators of such sources and units must surrender allowances only if 

the units’ emissions (referred to as the common designated 

representative’s share of emissions) during the control period 

involved exceed the units’ allocations plus share of the state 

variability limit (referred to as the common designated 

representative’s share of the state trading budget with variability). 

As discussed elsewhere in this preamble, EPA decided to 

implement the assurance provisions on a common designated 

representative basis, rather than on an owner basis. The final rules 

implement in a series of steps the process of determining which 

states have total covered-unit emissions sufficient to trigger the 

allowance surrender requirement for a given control period and 

determining, using the approach based on common designated 

representatives, which owners and operators are subject to the 

allowance surrender and whether those owners and operators are in 

compliance. This common-designated-representative-based process is 

more streamlined than the owner-based process in the proposed rules.
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First, the Administrator performs the calculations necessary to 

determine whether any state has total covered-unit emissions for a 

control period greater than the state trading budget with the 1-year 

variability limit. As discussed elsewhere in this preamble, EPA 

decided not to use a 3-year variability limit because, among other 

things, such a limit seems unnecessary to ensuring elimination of 

significant contribution to nonattainment and interference with 

maintenance and would make compliance planning extremely difficult 

for owners and operators. By June 1, 2013 and June 1 of each year 

thereafter, the Administrator promulgates a notice of data 

availability of the results of these calculations.

Second, by July 1, for states identified in the June 1 notice of 

data availability as having emissions exceeding the state trading 

budget with variability, the designated representative of each new 

unit in the state that operated during but did not receive an 

allocation for the year involved must submit a statement to the 

Administrator with certain information about the unit. This 

information -- i.e., the unit’s allowable emission rate for the 

pollutant involved (NOX or SO2) and heat rate -- is used to calculate 

a surrogate allocation for the unit to be used solely for the 

purposes of determining whether the group of units with a common 

designated representative that includes the unit had emissions 

exceeding allocations plus share of the state’s variability limit. 

Third, the Administrator calculates, for each state identified 

in the June 1 notice of data availability and for each common 
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designated representative of a group of units (which groups can 

include one or more units and sources) in the state, the common 

designated representative’s share of emissions, the common designated 

representative’s share of the state trading budget with the 

variability limit, and the amount (if any) that the groups of owners 

and operators of units represented by the common designated 

representative (which groups can include one or more owners and 

operators) in the state must surrender under the assurance provisions 

(i.e., the common designated representative’s proportionate share of 

the excess of state emissions over the state trading budget with the 

variability limit). The Administrator promulgates by August 1 a 

notice of data availability of the results of these calculations, 

provides an opportunity for submission of objections, and promulgates 

by October 1 a second notice of data availability of any necessary 

adjustments to the calculations. In contrast with the proposed 

rules, objections may be submitted concerning information in the 

August 1 notice, whether or not that information was also provided in 

the June 1 notice. In short, the process of issuing notices is 

shortened in the final rules by providing one, comprehensive 

opportunity to submit objections to the June 1 and August 1 notices, 

rather than two separate opportunities, one for each notice.

Also in contrast with the proposed rules, the deadlines for 

issuance of notices of data availability for implementation of the 

assurance provisions are made uniform under the final rules for all 

of the Transport Rule trading programs. EPA is taking this approach 
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for the same reasons that the deadlines for issuance of notices of 

data availability for new unit set-aside allocations are made uniform 

for all of these trading programs. 

Fourth, the owners and operators identified in the October 1 

notice of data availability as being required to surrender allowances 

under the assurance provisions must transfer, by November 1, to the 

assurance account created by the Administrator for such owners and 

operators the amount of allowances (usable for compliance) that the 

Administrator determined in the October 1 notice of data 

availability. Where the October 1 notice indicates that a specified 

surrender amount is owed by a group of two or more owners and 

operators, all the group members are liable for the surrender amount, 

and it is up to the owners and operators in the group to decide who 

will actually surrender allowances. This is analogous to the 

situation where a group of two or more owners and operators of 

covered units at a source is required to hold allowances covering the 

unit’s emissions and therefore the group of owners and operators is 

liable. See 58 FR 3590, 3599 (January 11, 1993) (discussing 

liability of owners and operators under allowance-holding 

requirements of the Acid Rain Program).

EPA believes that the approach of making the owners and 

operators responsible for deciding which of them will actually 

surrender the necessary allowances under the assurance provisions is 

reasonable because the identity of who is an owner or operator 

(particularly who is an owner) of a unit or source and the percentage 
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of an owner’s share can change during the year and this information 

is available to the owners and operators on an ongoing basis, and not 

to EPA unless EPA were to impose new requirements for reporting this 

information. Further, EPA believes that it is reasonable to leave to 

private agreements the establishment of procedures for determining 

when, and under what conditions, specific owners and operators will 

provide the allowances for surrender. Owners and operators already 

make these types of determinations with regard to the surrender 

requirements in meeting the emissions limitations and any excess 

emission penalties.

As part of implementing the common-designated-representativebased approach of the assurance provisions in the final Transport 

Rule, the final rules provide that the Administrator (instead of the 

owners, as in the proposed rules) will create an assurance account 

for each group of the owners and operators of units and sources with 

a common designated representative in each state where the assurance 

provisions are triggered. Because the final rules require owners and 

operators to transfer surrendered allowances to the appropriate 

assurance account (rather than requiring the Administrator to deduct 

from accounts established by the owners), there is no need for the 

proposed rule provisions concerning identification of which 

allowances are to be deducted and first-in, first-out deduction in 

the absence of such identification.

The final rules provide that, in general, the surrender amounts 

specified in the October 1 notice for owners and operators are final 
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and will not be revised even if the underlying data (e.g., emission 

data) used in the calculations underlying the October 1 notice are 

subsequently revised. However, the final rules set forth limited 

exceptions to this: where such data are revised as a result of a 

decision in or settlement of litigation concerning the data on 

appeal. EPA believes that the limitation on revisions of the 

surrender amounts specified in the October 1 notice are necessary to 

provide some certainty to owners and operators and avoid the 

potential for multiple changes in owners’ and operators’ required 

surrender amounts. Because the surrender amount for each group of 

owners and operators of units and sources with a common designated 

representative in a state is calculated using emission data from all 

of the covered units in that state, each change in one or a few 

units’ emission data that might occur after issuance of the October 1 

notice could otherwise change the calculated surrender amounts for 

all or many groups in the state. For the limited exceptions where 

the final rules provide that the surrender amounts specified in the 

August 1 notice may be revised, the final rules require the 

Administrator to set a new surrender deadline for any additional 

surrender required and to transfer allowances back out of the 

assurance account involved for any reduced surrender requirement, as 

appropriate.

Under the final rules (as under the proposed rules), it is not a 

violation of the CAA for total state covered-unit emissions to exceed 

the state trading budget with the variability limit or for a group of 
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owners and operators to become subject to the allowance surrender 

requirement under the assurance provisions. However, the failure of 

any group of owners and operators to surrender the required amount of 

allowances in the assurance account created for such owners and 

operators violates the CAA and is subject to discretionary penalties, 

with each required allowance that was not surrendered and each day of 

the control period involved constituting a violation. 

(v) §§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 in the final rules (as in the proposed rules) 

include provisions allowing 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. While this can 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 limit such emissions in a way that 

ensures that each state’s significant contribution to nonattainment 

and interference with maintenance that EPA has identified in this 

action will be eliminated.

These sections also include provisions stating that the 

Administrator can, 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 

can review any submission under the Transport Rule trading programs, 
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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 establish emissions 

monitoring, recordkeeping, and reporting requirements for Transport 

Rule units. 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 set forth. 

The provisions in the final rules are virtually the same as the 

monitoring, recordkeeping, and reporting requirements in the proposed 

rules and under previous EPA-administered trading programs, e.g., the 

Acid Rain Program and NOX Budget and CAIR trading programs. The final 

rule provisions are also essentially the same for each of the 

Transport Rule trading programs, except for differences reflecting 

the different pollutants and control periods involved.

Under the provisions of the final rules and under Part 75, a 

unit has several options for monitoring and reporting. A unit’s 

options are to use: 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, unit owners and operators may submit, and the 

Administrator can approve, petitions for alternatives to Transport 
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Rule and Part 75 monitoring, recordkeeping, and reporting 

requirements. 

As discussed elsewhere in this preamble, the final rules and 

Part 75 specify that each CEMS must undergo rigorous initial 

certification testing and periodic quality assurance testing 

thereafter. In addition, when a monitoring system is not operating 

properly, standard substitute data procedures are applied and result 

in a conservative estimate of emissions for the period involved. 

Further, the final rules and Part 75 require electronic submission, 

to the Administrator and in a format prescribed by the Administrator, 

of a quarterly emissions report. 

The final rules include revised language in §§97.430(b)(3), 

97.530(b)(3), 97.630(b)(3), and 97.730(b)(3) that incorporates by 

reference, and thereby applies to units in the Transport Rule trading 

programs, clarification that EPA recently adopted in §75.4(e) of Part 

75 (for Acid Rain Program units) concerning the requirements for 

certification, recertification, and diagnostic testing of emission 

monitoring systems when a unit adds a new stack or new add-on SO2 or 

NOX emission control device. See 76 FR 17288, 17298-300 (March 28, 

2011). The revised language is adopted for the reasons set forth in 

the preamble of that Acid Rain Program final rule and in order to 

continue the approach, in the Transport Rule trading program rules, 

of adopting monitoring, recordkeeping, and reporting requirements 

that are generally consistent with those in the Acid Rain Program, 

which covers many units in the Transport Rule trading programs.
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XII. Statutory and Executive Order Reviews

The projected impacts of this final rule as presented throughout 

the preamble do not reflect minor technical corrections to SO2 budgets 

in three states (KY, MI, and NY) made after the impact analyses were 

conducted. These projections also assumed preliminary variability 

limits that were smaller than the variability limits finalized in 

this rule. EPA conducted sensitivity analysis confirming that these

differences do not meaningfully alter any of the Agency’s findings or 

conclusions based on the projected cost, benefit, and air quality 

impacts presented for the final Transport Rule. The results of this 

sensitivity analysis are presented in Appendix F in the final 

Transport Rule RIA.

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory Review

Under EO 12866 (58 FR 51735, October 4, 1993), this action is an 

“economically significant regulatory action” because it is likely to 

have an annual effect on the economy of $100 million or more or 

adversely affect in a material way the economy, a sector of the 

economy, productivity, competition, jobs, the environment, public 

health or safety, or state, local, or tribal governments or 

communities.

Accordingly, EPA submitted this action to the OMB for review 

under EO 12866 and EO 13563 (76 FR 3821, January 21, 2011) and any 

changes in response to OMB recommendations have been documented in 
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the docket for this action. In addition, EPA prepared an analysis of 

the potential costs and benefits for this action. This analysis is 

contained in the Regulatory Impact Analysis (RIA) for this action. 

For more information on the costs and benefits for this rule, please 

refer to Table VIII.C-3 of this preamble.

When estimating the human health benefits and compliance costs 

in Table VIII.C-3 of this preamble, 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 this rulemaking. The 

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. In doing what is laid 

out above in this paragraph, EPA adheres to EO 13563, “Improving 

Regulation and Regulatory Review,” (76 FR 3,821, January 21, 2011), 

which is a supplement to EO 12866.

In addition to estimating costs and benefits, EO 13563 focuses 

on the importance of a “regulatory system [that]...promote[s] 

predictability and reduce[s] uncertainty” and that “identify[ies] and 

use[s] the best, most innovative, and least burdensome tools for 

achieving regulatory ends.” EO 13563 also states that “[i]n 

developing regulatory actions and identifying appropriate approaches, 

each agency shall attempt to promote such coordination, 
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simplification, and harmonization. Each agency shall also seek to 

identify, as appropriate, means to achieve regulatory goals that are 

designed to promote innovation.” We recognize that the utility 

sector has compliance obligations related to multiple environmental 

statutes authorizing regulatory action, including this rule’s 

requirements to reduce interstate transport of harmful ozone and fine 

particles and their precursors, as well as other rules’ requirements 

to reduce air toxic emissions, to reduce greenhouse gas emissions, to 

safely manage coal combustion wastes, and to protect aquatic wildlife 

from water intake procedures. In the wake of promulgating this final 

rule, EPA recognizes that moving forward the agency needs to approach

these rulemakings in ways that allow the industry to make practical 

investment decisions that minimize costs in complying with all of the 

final rules, while still securing the fundamentally important 

environmental and public health benefits that led Congress to enact 

those authorities in the first place. At the same time, EPA notes 

that the flexibility inherent in the allowance-trading mechanism 

included in this rule affords utilities themselves a degree of 

latitude to determine how best to integrate compliance with the 

emission reduction requirements of this rule and those of the other 

rules.

The final rule will also reduce emissions of directly emitted PM 

and ozone precursors, and estimates of the PM2.5-related benefits of 

these air quality improvements may be found in Tables VIII.C-1 and 

VIII.C-2 of this preamble. When characterizing uncertainty in the 
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PM-mortality relationship, EPA has historically presented a 

sensitivity analysis applying alternate assumed thresholds in the PM 

concentration-response relationship. In its synthesis of the current 

state of the PM science, EPA’s 2009 Integrated Science Assessment for 

Particulate Matter concluded that a no-threshold log-linear model 

most adequately portrays the PM-mortality concentration-response 

relationship. In the RIA accompanying this rulemaking, rather than 

segmenting out impacts predicted to be associated levels above and 

below a “bright line” threshold, EPA includes a “lowest measured 

level” (LML) analysis that illustrates the increasing uncertainty 

that characterizes exposure attributed to levels of PM2.5 below the 

LML of each epidemiological study used to estimate PM2.5-related 

premature death. Figures provided in the RIA show the distribution 

of baseline exposure to PM2.5, as well as the lowest air quality 

levels measured in each of the epidemiology cohort studies. This 

information provides a context for considering the likely 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 diminishes as baseline 

concentrations of PM2.5 are lowered. Approximately 69 percent of the 

avoided impacts occur at or above an annual mean PM2.5 level of 10 

μg/m3 (the LML of the Laden et al. 2006 study); about 96 percent occur 

at or above an annual mean PM2.5 level of 7.5 μg/m3 (the LML of the 

Pope et al. 2002 study). Although the LML analysis provides some 

insight into the level of uncertainty in the estimated PM mortality 
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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. It is important to note that the 

monetized benefits include many but not all health effects associated 

with PM2.5 exposure. Benefits are shown as a range from Pope, et al., 

(2002) to Laden, et al., (2006). 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.

The cost analysis is also subject to uncertainties. Estimating 

the cost conversion from one process to another is more difficult 

than estimating the cost of adding control equipment because it is 

more dependent on plant specific information. More information on 

the cost uncertainties can be found in the RIA.

A summary of the monetized benefits and net benefits for the 

final rule at discount rates of 3 percent and 7 percent is in Table 

VIII.C-3 of this preamble. For more information on the benefits 

analysis, please refer to the RIA for this rulemaking, which is 

available in the docket.

B. Paperwork Reduction Act

EPA is required to document the information collection burden 

imposed by the Transport Rule on industry, states, and EPA in an 

information collection request (ICR). The ICR describes the 

information collection requirements associated with the Transport 
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Rule and estimates the incremental costs of compliance with all such 

requirements, such as the requirement for industry to monitor, 

record, and report emission data to EPA.

The ICR for the final Transport Rule has been submitted for 

approval by OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et

seq., and the information collection requirements it documents are 

not enforceable until such approval has been granted. An ICR was 

also submitted to OMB in support of the proposed Transport Rule; no 

adverse comment was received by EPA on either the information 

collection requirements or their associated cost estimates as 

described in that document.

The costs associated with the information collection 

requirements of the Transport Rule include start-up and capital costs 

for units newly affected by an emission trading program, or whose 

reporting status has changed (e.g., from ozone-season-only to annual 

reporting), as well as the additional operation and maintenance costs 

for Transport Rule-affected units already participating in an EPAadministered cap and trade program. More information on the ICR 

analysis is included in the final Transport Rule docket. 

The records and reports generated by these activities will be 

used by EPA and states to ensure that affected facilities comply with 

emission limits and other requirements. Such records and reports are 

also helpful to EPA and states in both identifying affected 

facilities that may not be in compliance with applicable requirements 
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and in discerning which units and what records or processes should be 

inspected.

The incremental capital and operating costs associated with the 

recordkeeping and reporting burden to Transport Rule-affected sources 

in states participating in the Transport Rule trading programs are 

approximately $26 million annually in 2010 dollars. The total number 

of burden hours associated with the recordkeeping and reporting 

burden to Transport Rule-affected sources in states participating in 

the Transport Rule trading programs is approximately 185,000 hours 

annually. These estimates include the annualized cost of installing 

and operating appropriate SO2 and NOX emission monitoring equipment to 

measure and report the total emissions of these pollutants from 

affected EGUs (serving generators greater than 25 MW). The burden to 

state and local air agencies, as documented in the ICR, includes any 

necessary SIP revisions, performance of monitor certifications, and 

fulfillment of audit responsibilities. Burden is defined at 5 CFR 

1320.3(b).

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, which is 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. An Agency may not conduct or sponsor, and a person is 
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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 final 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 (MWh) or less in the previous 

fiscal year.
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(2) A small governmental jurisdiction that is a government of a 

city, county, town, school district or special district with a 

population of less than 50,000; and

(3) A small organization that is any not-for-profit enterprise 

which is independently owned and operated and is not dominant in its 

field. 

Table XII.C-1 — Potentially Regulated Categories and Entitiesa

Category NAICS 

Codeb

Examples of Potentially Regulated

Entities

Industry 221112 Fossil-fuel-fired electric utility 

steam generating units.

Federal 

Government

221112c Fossil-fuel-fired electric utility 

steam generating units owned by the 

federal government.

State/Local 

Government

221112c Fossil-fuel-fired electric utility 

steam generating units owned by 

municipalities.

Tribal 

Government

921150 Fossil-fuel-fired electric utility 

steam generating units in Indian 

Country.

a Include NAICS categories for source categories that own and operate 

electric generating units only.

b North American Industry Classification System.

c Federal, state, or local government-owned and operated 

establishments are classified according to the activity in which they 

are engaged.

EPA used Velocity Suite’s Ventyx data as a basis for identifying 

plant ownership and compiling the list of potentially affected small 

entities. For plants burning fossil fuel as the primary fuel, 
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plant-level boiler and generator capacity, heat input, generation, 

and emission data were aggregated by owner and then parent company. 

For cooperatives, investor-owned utilities, and subdivisions that 

generate less than 4 billion kWh of electricity annually but may be 

part of a large entity, additional research on power sales, operating 

revenues, and other business activities was performed to make a final 

determination regarding size.

After considering the economic impacts of this final rule on 

small entities, EPA certifies that this action will not have a 

significant economic impact on a substantial number of small entities 

(No SISNOSE). This certification is based on the economic impact of 

this final rule to all affected small entities across all industries 

affected. EPA assessed the potential impact of this action on small 

entities and found that there are about 660 potentially affected 

small units (i.e., greater than 25 MW and generating less than 4 

million MWh) out of 3,625 existing units in the Transport Rule 

states. The majority of these EGUs are owned by entities that do not 

meet the small entity definition. The remaining 271 of the 660 EGUs 

are owned by 108 potentially affected small entities and are likely 

to be affected by this rule. EPA estimates that 24 of the 108 

identified small entities will have annualized costs greater than 1 

percent of their revenues, and the other 84 are projected to incur 

costs less than 1 percent of revenues. Eleven small entities out of 

108 -- approximately 10 percent -- are estimated to have annualized 

costs greater than 3 percent of their revenues. EPA has lessened the 
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impacts for small entities by excluding all units smaller than 25 

MWe. This exclusion, in addition to the exemptions for cogeneration 

units and solid waste incineration units, eliminates the burden of 

higher costs for a substantial number of small entities located in 

the Transport Rule states.

While the total number of small entities has increased compared 

to the proposal as a result of updated modeling and changes in 

geographic coverage, the number with compliance costs greater than 1 

percent of revenues has fallen, and both the number and percentage of 

significantly impacted small entities (costs greater than 3 percent 

of revenues) are lower -- now 10 percent compared to 17 percent in 

the proposal. The share of significantly impacted small entities has 

fallen because of updated modeling and the change in the allowance 

allocation methodology (see section VII.D for more information about 

allowance allocations).

Although this final rule will not have a significant economic 

impact on a substantial number of small entities, EPA nonetheless has 

tried to reduce the impact of this rule on small entities. In EPA’s 

modeling, most of the cost impacts for these small entities and their 

associated units are driven by lower electricity generation relative 

to the base case. Specifically, two small units reduce their 

generation by significant amounts, driving the bulk of the costs for 

all small entities. Excluding these two units, one of the main 

drivers of small entity impacts is higher fuel costs, which the 

affected units would incur irrespective of whether they had to comply 
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with this rule. In addition, EPA’s decision to exclude units smaller 

than 25 MWe has already significantly reduced the burden on 

approximately 390 small entities.

For more information on the small entity impacts associated with 

the final rule, refer to the Regulatory Impact Analysis for this 

final rule, which can be found in the docket for this rule and on the 

website www.epa.gov/airtransport. 

D. Unfunded Mandates Reform Act

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 1 year. Accordingly, EPA 

has prepared, under section 202 of the UMRA, a written statement 

which is summarized later.

Consistent with the intergovernmental consultation provisions of 

section 204 of the UMRA, EPA held consultations with the governmental 

entities affected by this rule during the proposal phase. 

Subsequently, EPA sent a letter to the ten Representative National 

Organizations to draw their attention to the Transport Rule Notice of 

Data Availability (NODA) on allowance allocations and other related 

matters and to invite their comments. During the NODA comment 

period, EPA participated in informational calls with the 
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Environmental Council of the States (ECOS) and the National Governors 

Association to provide information about the NODA directly to state 

and local officials. There were no new concerns raised during these 

informational calls. In addition, EPA also conducted consultations 

with federally recognized tribes prior to finalizing this rule and 

invited them to comment on the allowance allocation NODA. EPA has 

added a new unit set-aside provision to this final rule specifically 

for EGUs constructed in Indian country to ensure allowances are 

available to tribes and tribal sovereignty is respected.

Consistent with section 205, EPA identified and considered a 

reasonable number of regulatory alternatives. In the proposal, EPA 

included three remedy options that it considered when developing this 

final rule: (1) the preferred remedy trading programs, (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 

municipality-owned entities associated with this rulemaking based on 

assumptions of how the affected states will implement control 

measures to meet program requirements. Although EPA does not 

conclude that the requirements of the UMRA apply to the Transport 

Rule, these impacts have been calculated to provide additional 
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understanding of the nature of potential impacts and additional 

information. 

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 final 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 

final rule primarily affects private industry, and does not impose 
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significant economic costs on state or local governments. Thus, 

Executive Order 13132 does not apply to the final rule.

Although section 6 of Executive Order 13132 does not apply to 

the final rule, EPA did provide information to state and local 

officials during development of both the proposal and final rule. 

EPA sent a letter to the ten Representative National Organizations to 

draw their attention to the Transport Rule NODA on allowance 

allocations and other related matters and to invite their comments. 

Following that letter in early 2011, EPA participated in 

informational calls with the Environmental Council of the States 

(ECOS) and the National Governors Association to provide information 

about the NODA directly to state and local officials. There were no 

new concerns raised during these informational calls.

F. Executive Order 13175: Consultation and Coordination with Indian 

Tribal Governments

Under Executive Order 13175 (65 FR 67249, November 9, 2000), EPA 

may not issue a regulation that has tribal implications, that imposes 

substantial direct compliance costs, and that is not required by 

statute, unless the federal government provides the funds necessary 

to pay the direct compliance costs incurred by tribal governments, or 

EPA consults with tribal officials early in the process of developing 

the proposed regulation and develops a tribal summary impact 

statement. 
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EPA has concluded that this action may have tribal implications 

if a new unit covered by the rule is built in Indian country. 

Additionally, tribes have a vested interest in how this final rule 

affects their air quality. However, it will neither impose 

substantial direct compliance costs on tribal governments, nor 

preempt tribal law. EPA consulted with tribal officials during the 

process of finalizing this regulation to permit them to have 

meaningful and timely input into its development.

EPA received comments on the proposed Transport Rule that the 

Agency did not properly conduct consultation during the proposal 

phase of the rulemaking process. In response to these comments, EPA 

sent a letter to all federally-recognized tribes in the country 

offering consultation. In addition, several commenters also noted 

that the Agency did not adequately consider opportunities for tribes 

to enter into any of the trading programs and, in particular, did not 

consider sovereignty issues when addressing how to distribute 

allowances to potential new units in Indian country. On January 7, 

2011, EPA issued a NODA requesting comment on allocations for new 

units in Indian country, among other topics.

The Agency held a consultation call with three tribes on January 

21, 2011. A follow-up call was held on February 4, 2011 with two of 

the three original tribes plus 13 additional tribes, as well as

representatives from the National Tribal Air Association. In all ten 

tribes participated in these calls as consultation and six

participated as information-sharing. EPA considered the additional 
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input from these consultation and information calls, in conjunction 

with the public comments, in the development of the final rule. 

Accordingly, EPA created an Indian country new unit set-aside to 

specifically address tribes’ concerns regarding the protection of 

tribal sovereignty in the distribution of allowances for new units in 

Indian country. See section VII.D.2 of this preamble for details on 

the Indian country set-aside for new units constructed in Indian 

country within states covered by the Transport Rule. 

As required by section 7(a) of the Executive Order, EPA’s Tribal 

Consultation Official has certified that the requirements of the 

Executive Order have been met in a meaningful and timely manner. A 

copy of the certification is included in the docket for this action.

G. Executive Order 13045: Protection of Children from Environmental 

Health and Safety Risks 

Executive Order 13045 (62 FR 19,885, April 23, 1997) applies to 

any rule that: 1) is determined to be “economically significant” as 

defined under EO 12866, and 2) concerns an environmental health or 

safety risk that EPA has reason to believe may have a 

disproportionate effect on children. If the regulatory action meets 

both criteria, the Agency must evaluate the environmental health or 

safety effects of this planned rule on children, and explain why this 

planned regulation is preferable to other potentially effective and 

reasonably feasible alternatives considered by the Agency.
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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. EPA believes that the 

emission reductions from the strategies in this rule will further 

improve air quality and will further improve children’s health. 

Analyses by EPA that show how the emission reductions from the 

strategies in this rule will further improve air quality and 

children’s health can be found in the RIA for this rule.

H. Executive Order 13211: Actions that Significantly Affect Energy 

Supply, Distribution, or Use

Executive Order 13211 (66 FR 28355, May 22, 2001) provides that 

agencies shall prepare and submit to the Administrator of the Office 

of Regulatory Affairs, OMB, a Statement of Energy Effects for certain 

actions identified as “significant energy actions.” Section 4(b) of 

Executive Order 13211 defines “significant energy action” as “any 

action by an agency (normally published in the Federal Register) that 

promulgates or is expected to lead to the promulgation of a final 

rule or regulation, including notices of inquiry, advance notices of 

proposed rulemaking, and notices of proposed rulemaking: (1) (i) 

that is a significant regulatory action under Executive Order 12866 

or any successor order, and (ii) is likely to have a significant 

adverse effect on the supply, distribution, or use of energy; or (2) 

that is designated by the Administrator of the Office of Information 

and Regulatory Affairs as a significant energy action.” This rule is 

a significant regulatory action under Executive Order 12866, and this 
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rule is likely to have a significant adverse effect on the supply, 

distribution, or use of energy. EPA prepared a Statement of Energy 

Effects for this action as follows.

Under the provisions of this rule, EPA projects that 

approximately 4.8 GW of additional 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. If current forecasts of either natural gas 

prices or electricity demand were revised in the future to be higher, 

that would create a greater incentive to keep these units 

operational.

EPA estimates that average retail electricity prices could 

increase in the contiguous U.S. by about 1.7 percent in 2012 and 0.8 

percent in 2014. This is generally less of an increase than often 

occurs with fluctuating fuel prices and other market factors. 

Related to this, EPA projects limited impacts on coal and gas prices. 

The average delivered coal price decreases by about 1.4 percent in 

2012 and 0.9 percent in 2014 relative to the base case as a result of 

decreased coal demand and shifts in the type of coal demanded. EPA 

also projects that the electric power sector-delivered natural gas 

price will increase by about 0.3 percent over the 2012-2030 timeframe 

and that natural gas use for electricity generation will increase by 
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approximately 200 billion cubic feet (BCF) by 2014. These impacts 

are well within the range of price variability that is regularly 

experienced in natural gas markets. Finally, under the Transport 

Rule, EPA projects that coal production for use by the power sector 

will increase above 2009 levels by 21 million tons in 2012 and a 

further 14 million tons in 2014, as opposed to 30 million tons in 

2012 and a further 26 million tons in 2014 without the Transport Rule 

in place. The Transport Rule is not projected to impact production 

of coal for uses outside the power sector (e.g., export, industrial 

sources), which represent approximately 6 percent of total coal 

production in 2009. EPA does not believe that this rule will have 

any other impacts (e.g., on oil markets) that exceed the significance 

criteria.

EPA believes that a number of features of the rulemaking serve 

to reduce its impact on energy supply. First, the trading component 

of the Transport Rule provides flexibility to the power sector and 

enables industry to comply with the emission reduction requirements 

in the most cost-effective manner compared to the alternative remedy 

approaches on which EPA took comment in the proposal, 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.
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For more details concerning energy impacts, see the RIA for the 

Transport Rule.

I. National Technology Transfer 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 rule will require all sources to meet the 

applicable monitoring requirements of 40 CFR part 75. Part 75 

already incorporates a number of voluntary consensus standards. 

Consistent with the Agency’s Performance Based Measurement System 

(PBMS), Part 75 sets forth performance criteria that allow the use of 

alternative methods to the ones set forth in Part 75. The PBMS 

approach is intended to be more flexible and cost effective for the 

regulated 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, 
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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. During 

development of this final Transport Rule, EPA considered its impacts 

on low-income, minority, and tribal communities in several ways and 

provided multiple opportunities for these communities to meaningfully 

participate in the rulemaking process. The proposed Transport Rule 

included an analysis of its effects on these populations; this 

section describes additional analysis conducted since proposal, EPA’s 

responses to key comments on environmental justice issues raised 
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during the comment period, and the public outreach and comment 

opportunities for this rule. 

A summary of the history, statutory authority, and key 

components of this final Transport Rule are described in the 

Executive Summary (section III) of this preamble. That section also 

summarizes a supplemental notice of proposed rulemaking (SNPR) that 

EPA is publishing to correct a procedural flaw by providing an 

opportunity for public comment on issues that arose from new analyses 

with updated inventories and modeling platforms. 

Briefly, this final Transport Rule will reduce emissions of SO2

and NOX in 23 eastern and central states in 2012 and 2014 that 

contribute to annual and/or 24-hour PM2.5 nonattainment or interfere 

with maintenance in downwind states. It will also reduce emissions 

of ozone-season NOX in 20 eastern and central states in 2012 and 2014 

that contribute to the 1997 ozone nonattainment or interfere with 

maintenance in downwind states. 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 in 2008. 

1. Consideration of Environmental Justice in the Transport Rule 

Development Process and Response to Comments

The effects of this final Transport Rule on the most highly 

exposed populations were integral in its development. This rule uses 

EPA’s authority in CAA section 110(a)(2)(d) to reduce sulfur dioxide 

(SO2) and (nitrogen oxides) NOX pollution that significantly 
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contributes to downwind PM2.5 and ozone nonattainment or maintenance 

areas. As a result, the rule will reduce exposures to ozone and PM2.5

in the most-contaminated areas (i.e., areas that are not meeting the 

1997 ozone and 1997 and 2006 PM2.5 National Ambient Air Quality 

Standards (NAAQS)). In addition, the rule separately identifies both 

nonattainment areas and maintenance areas (maintenance areas are 

those that are projected to meet the NAAQS but that, based on past 

data, are in danger of exceeding the standards in the future). This 

requirement reduces the likelihood that any areas close to the level 

of the standard will exceed the current health-based standards in the 

future.

This final Transport Rule implements these emission reductions 

using an emission trading mechanism with assurance provisions for 

power plants. EPA recognizes that many environmental justice 

communities have voiced concerns in the past about emission trading 

and the potential for any emission increases in any location. EPA 

also received several comments on this issue during the comment 

period for the proposed Transport Rule. As described below, we 

believe this final rule addresses the concerns raised on this issue 

during the comment period.

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 emission 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 
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instances the exact location of the upwind reductions does not affect 

the levels of air pollution downwind. 

It is important to note that the section of the Clean Air Act 

providing authority for this rule, section 110(a)(2)(D), unlike some 

other provisions, does not dictate levels of control for particular 

facilities. As at least one commenter noted, none of the 

alternatives put forward by EPA in the proposed rule could have 

ensured no emission increases at any facility. Under the direct 

control alternative, the emission rate for each facility would have 

been limited 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, sources could not trade 

allowances with sources in other states but individual facilities 

within each state could have increased their emissions as long as 

another facility in the state had decreased theirs at some time.

The final Transport Rule allows sources to trade allowances with 

other sources in the same or different states while firmly 

constraining any emissions shifting that may occur by requiring a 

strict emission ceiling in each state (the budget plus variability 

limit). In addition, assurance provisions in the rule outline the 

allowance surrender penalties for failing to meet the budget plus 

variability limits; there are additional allowance penalties as well 

as financial penalties for failing to hold an adequate number of 

allowances to cover emissions. This approach eliminates emissions in 

each state that significantly contribute to downwind nonattainment or 
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maintenance areas, while allowing power companies to adjust 

generation as needed and ensure that the country’s electricity needs 

will continue to be met. EPA maintains that the existence of these 

assurance provisions, including the penalties imposed when triggered, 

will ensure that state emissions will stay below the level of the 

budget plus variability limit.

In addition, all sources must hold enough allowances to cover 

their emissions. Therefore, if a source emits more than its 

allocation in a given year, either another source must have used less 

than its allocation and be willing to sell some of its excess

allowances, or the source itself had emitted less than its allocation 

in one or more previous years (i.e., banked allowances for future 

use). 

In summary, the final remedy addresses commenter concerns about 

localized hot spots and reduces ambient concentrations of pollution 

where they are most needed by sensitive and vulnerable populations 

by: considering the science of ozone and PM2.5 transport to set 

strict state budgets to eliminate significant contributions to ozone 

and PM2.5 nonattainment and maintenance (i.e., the most polluted) 

areas; implementing air quality-assured trading; requiring any 

emissions above the level of the allocations to be offset by emission 

decreases; and imposing strict penalties for sources that contribute 

to a state’s exceedance of its budget plus variability limit. In 

addition, it is important to note that nothing in this final rule 
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allows sources to violate their title V permit or any other federal, 

state, or local emissions or air quality requirements.

EPA received comments from several tribal commenters regarding 

the lack of allocations in the proposal to new units in Indian 

Country. EPA responded to these comments by changing the allocation 

approach in the final rule to create Indian country new unit setasides. In order to protect tribal sovereignty, these set-asides 

will be managed and distributed by the federal government regardless 

of whether the Transport Rule in the adjoining or surrounding state 

is implemented through a FIP or SIP. While there are no existing 

power plants in Indian country covered by this Transport Rule, the 

Indian country set-asides will ensure that any future new units built 

in Indian country will be able to get the necessary allowances. A 

full discussion of the Indian country new unit set-asides can be 

found in section VII.D.2.

EPA also received several comments during the comment period 

from individuals and groups requesting additional emission reductions 

to further protect sensitive and vulnerable communities. While EPA 

has adjusted the emission requirements somewhat in the final rule to 

accommodate revised data and updated modeling results, we are 

finalizing emission reductions very similar to the level in the 

proposal. This is because EPA believes that the emission reductions 

required by this final rule are appropriate to meet the statutory 

requirements of CAA section 110(a)(2)(d) and respond to the concerns 
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raised by the Court’s opinion in North Carolina that remanded CAIR to 

the Agency in 2008. 

In addition, it is important to note that CAA section

110(a)(2)(d), which addresses transport of criteria pollutants 

between states, 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 for minority, low-income, and tribal populations, and 

provide substantial health benefits to both the general public and 

sensitive sub-populations.

For example, the recently-proposed Mercury and Air Toxics 

Standards (MATS) would also result in significant reductions in SO2

emissions and provide significant health and environmental benefits 

nationwide. This and other actions described in section III 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 will continue to provide multiple opportunities for 

comment on these actions, similar to the opportunities provided 

during the comment process for this rule, detailed at the end of this 

section. We encourage environmental justice communities to review 

and comment on these actions.
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2. Potential Environmental and Public Health Impacts among 

Populations Susceptible or Vulnerable to Air Pollution

EPA expects that this final rule will provide significant health 

and environmental benefits to, among others, people with asthma, 

people with heart disease, and people living in ozone or PM2.5

nonattainment areas. EPA’s analysis of the effects of this rule, 

including information on air quality changes and the resulting health 

benefits, is presented both in section VIII of this preamble and in 

the Regulatory Impact Analysis (RIA) for this rule. These documents 

can be accessed through the rule docket No. EPA-HQ-OAR-2009-0491 and 

from the main EPA webpage for the rule at www.epa.gov/airtransport.

EPA considered several aspects of the effects of the Transport 

Rule on minority, low-income, and tribal populations. These 

included: amount of emission reductions and where they take place 

(including any potential for areas of increased emissions); the 

changes in ambient concentrations across the affected area; the 

estimated health benefits; and how the estimated health benefits are 

distributed among different populations, including those susceptible 

and vulnerable to air pollution health impacts.

a. Emission Reductions

EPA’s emission modeling data indicate that implementation of the 

Transport Rule will substantially reduce SO2 emissions from electric 

generating units (EGUs). As noted in section III, emissions in 

states covered by the Transport Rule will decrease by 6.4 million 

tons (73 percent) in 2014 compared to 2005 (the year the Clean Air 
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Interstate Rule was finalized). Emissions are also projected to 

decrease when compared to the base case (the base case estimates 

emissions in 2014 in the absence of this rule or the Clean Air 

Interstate Rule it is replacing). EPA estimates that SO2 emissions in 

2014 in covered states will be 3.9 million tons lower (62 percent 

lower) compared to the base case.

EPA also assessed emission changes in states not covered by the 

Transport Rule. Emissions in the states not covered by the Transport 

Rule are also projected to decrease substantially compared to 2005 

levels; in 2014 SO2 emissions are projected to be approximately 

430,000 tons lower (30 percent lower) than in 2005. 

As described in section VI.C, EPA’s modeling does project that 

some states not covered by any of the fine particle control programs 

in the final Transport Rule may experience increases of SO2 emissions 

greater than 5,000 tons compared to the base case. These states are 

Arkansas, Colorado, Louisiana, Montana, and Wyoming. These emission 

increases are the result of forecasted changes in operation of power 

plant units outside of the Transport Rule states due to the 

interconnected nature of the utility grid (i.e., shifts in generation 

of electricity to sources outside the Transport Rule states) or 

influence of the rule on the market for lower sulfur coal. For 

example, EPA projects that the rule will raise demand for lower 

sulfur coal in the states covered by the Transport Rule for PM2.5

(thereby raising its price), which may lead sources in states not 
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covered for PM2.5 to choose higher-sulfur coals that increase SO2

emissions in those states.

EPA is not requiring SO2 emission reductions in these states 

under this rule because our modeling indicates none of these states’ 

contributions would increase enough to cause them to meet or exceed 

the thresholds described in section V.D for either of the PM2.5

standards. EPA’s authority under CAA section 110(a)(2)(d) is limited 

to addressing this significant contribution to nonattainment and 

interference with maintenance. However, as noted above, EPA has 

recently proposed the Mercury and Air Toxics Standards that will

apply nationwide and result in substantial additional SO2 emission 

reductions, including in states not covered by the Transport Rule.

EPA’s emission modeling data indicates that ozone-season NOX

emissions from EGUs in states covered by the Transport Rule will be 

approximately 340,000 tons lower (36 percent lower) in 2014 than they 

were in 2005. Emissions in states not covered by the Transport Rule 

are also expected to decrease somewhat (approximately 82,000 tons or 

25 percent). EPA’s modeling does project that two states (California 

and Pennsylvania) may experience increases of NOX emissions greater 

than 5,000 tons in 2014 compared to 2005 levels. California is not 

covered by the Transport Rule; in Pennsylvania, 2005 was an unusually 

low-emitting year and sources are projected to increase their heat 

input slightly (usually meaning they are generating more power) after 

the rule takes effect. 
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EPA also assessed the expected changes in seasonal NOX emissions 

with implementation of the Transport Rule compared to the base case 

(i.e., without the rule) in 2014. The modeling indicates ozoneseason NOX emissions from EGUs in both covered states and nonTransport Rule states under this rule will be lower than they would 

have been in 2014 in the base case. Ozone-season NOX emissions in 

covered states are projected to decrease by approximately 74,000 tons 

(11 percent); ozone-season NOX emissions in non-Transport Rule states 

are projected to decrease by approximately 10,000 tons (4 percent). 

Both California and Pennsylvania are projected to have lower NOX

emissions in 2014 under the Transport Rule as compared to the base 

case. In addition, EPA anticipates that additional upcoming actions, 

including likely additional interstate transport reductions to help 

states attain the upcoming new ozone NAAQS, will result in 

significant additional NOX reductions in the future.

b. Air Quality Improvements 

EPA assessed the air quality metrics (called “design values”) 

for each NAAQS addressed in this rule: 24-hour PM2.5, annual PM2.5, 

and ozone. We then compared these metrics for the final rule to the 

same metrics in the recent past (2003-2007 average ambient air 

quality) and for the 2014 base case to assess improvements in air 

quality.

EPA’s modeling indicates that there will be significant 

improvements in air quality as measured by the 24-hour PM2.5 standard. 

Throughout much of the eastern half of the U.S., 24-hour PM2.5 design 
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values are projected to improve more than 10 μg/m

3 compared to the 

2003-2007 average levels. In addition, compared to the 2014 base 

case levels, we project the Transport Rule will result in 

improvements of 8-10 μg/m

3 in a broad swath of states stretching from 

far southwestern New York through Pennsylvania, Ohio, West Virginia, 

Maryland, Indiana, southern Illinois, eastern Missouri, eastern 

Arkansas, Kentucky, Tennessee, northern Alabama, and northern 

Mississippi. Isolated areas of Virginia and northern New Jersey are 

also expected to see this level of improvement. Improvements of 2-6 

μg/m3 are projected in surrounding states stretching from New England 

and New York to Minnesota, Iowa, the far eastern edge of Nebraska, 

Missouri, eastern Kansas, Oklahoma, Texas, the Gulf of Mexico states, 

and the states bordering the Atlantic Ocean from Florida to New 

Hampshire.

EPA modeling indicates that air quality as measured by the 

annual PM2.5 design value will also improve. Improvements range from 2 

to over 4 μg/m3 compared to the 2003-2007 average levels throughout 

the eastern half of the U.S. Annual PM2.5 air quality with the 

Transport Rule is also projected to improve compared to the 2014 base 

case levels. The largest improvements of up to 4 μg/m3 are projected 

to occur in northern West Virginia and a small area in northwestern 

Tennessee. Improvements of up to 3 μg/m3 are projected for portions 

of the Ohio River valley areas of southwestern Pennsylvania, Ohio, 

West Virginia, Kentucky, central Tennessee, and southern Indiana. 

Improvements of up to 2 μg/m3 are projected to take place in a ring of 
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surrounding states including all or most of New York, Michigan, 

Indiana, Illinois, Missouri, Arkansas, the far eastern edge of

Oklahoma, the northeastern edge of Texas, Louisiana, Mississippi, 

Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, 

Delaware, Pennsylvania, and New Jersey. Smaller improvements are 

projected in New England, Wisconsin, the Plains states, southeastern 

New Mexico, and Florida.

EPA modeling indicates that ozone air quality will improve 

greatly (10-12 ppb or more) across much of the eastern U.S. between 

the average levels seen in 2003-2007 and implementation of the 

Transport Rule. Most of the improvements take place in the base 

case; that is, they are the result of federal and state programs 

other than the Transport Rule. However, ozone air quality is

projected to improve somewhat as a direct result of the Transport 

Rule. Improvements in ozone design values compared to the base case 

of more than 1 ppb are projected for portions of Florida, eastern 

Oklahoma, and areas along the upper reaches of the Ohio River. In 

addition, improvements in ozone design values of up to 1 ppb are 

projected over a wide area across the eastern U.S. from New England 

to Texas and north to Minnesota. Improvements are also projected in 

north-central Colorado. 

EPA’s modeling does indicate small increases in annual PM2.5 air 

quality design values in the final rule compared to the 2014 base 

case in two counties outside of the Transport Rule states: one 

county in northern Colorado and one county in eastern Montana. As 
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noted above in the section on emissions, these increases are likely 

the result of forecasted changes in electricity generation due to the 

interconnected nature of both the utility grid and the national lowsulfur coal market. It should be noted that 2003-2007 average air 

quality levels in these counties are well below the level of the 

NAAQS. In addition, other actions, including federal rules such as 

the recently proposed Mercury and Air Toxics Standards, state, or 

local actions may also improve air quality in these areas over the 

next few years.

As described in section VIII.B, EPA anticipates that this final 

rule will reduce, but not eliminate, the number of nonattainment and 

maintenance areas for the 1997 ozone and PM2.5 and 2006 PM2.5 NAAQS. 

As noted above, ozone and PM2.5 concentrations are the result of both 

local emissions and long-range transport of pollution. Even when the 

significant contributions of upwind states are fully eliminated, 

additional emission reductions within the nonattainment area and/or 

the downwind state will be needed for some areas to attain and 

maintain the NAAQS.

c. Estimated Health Benefits

This rule reduces concentrations of PM2.5 and ozone pollution. 

Exposure to these pollutants can cause, or contribute to, adverse 

health effects that affect many minority, low-income, and tribal 

individuals and 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 
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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 heart disease (e.g., high blood pressure)124 and 

asthma125 exist in many environmental justice communities, making these 

populations more susceptible to air pollution health impacts. In 

addition, many individuals in these communities lack access to high 

quality health care to treat these illnesses126.

We estimate that in 2014 the PM-related annual benefits of the 

final rule include approximately 13,000 to 34,000 fewer premature 

mortalities, 8,700 fewer cases of chronic bronchitis, 15,000 fewer 

non-fatal heart attacks, 8,500 fewer hospitalizations (for 

respiratory and cardiovascular disease combined), 10 million fewer 

days of restricted activity due to respiratory illness, and 

approximately 1.7 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.

 

124 Neighborhood of Residence and Incidence of Coronary Heart Disease 

Ana V. Diez Roux, M.D., Ph.D. et al. N Engl J Med 2001; 345:99-106; 

July 12, 2001.

125 Centers for Disease Control and Prevention. 2007 National Health 

11. Interview Survey Data. Table 4-1. Current Asthma Prevalence 

Percents by Age, United States: National Health Interview Survey, 

2007. Atlanta, GA: U.S. Department of Health and Human Services, CDC, 

2010. Accessed June 1, 2010.

126R. Nelson, Eds. National Institute of Medicine, 2003.
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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 (in addition to the PMrelated benefits above) between 27-120 fewer premature mortalities, 

240 fewer hospital admissions for respiratory illnesses in children 

and older adults, 86 fewer emergency room admissions for asthma, 

160,000 fewer days with restricted activity levels, and 51,000 fewer 

“school absence” days when children are absent from school due to 

illnesses. When adding the PM and ozone-related mortalities 

together, we find that the final rule will yield between 13,000 and 

34,000 fewer premature mortalities. 

It should be noted that, as discussed in the RIA, there are 

other benefits to the emission reductions discussed here, including 

many other health benefits beyond reducing the risk of premature 

mortality. Additional benefits of reducing emissions of SO2 include 

improved visibility, reduced acidification of lakes and streams, and 

reduced mercury methylation in contaminated waters; additional 

benefits of NOX reductions include improved visibility, reduced 

acidification of lakes and streams, and reduced coastal 

eutrophication. 

d. Distribution of Health Benefits Among Different Populations

EPA also estimated the PM2.5 mortality risks according to race, 

income, and educational attainment before and after implementation of 

this Transport Rule. We used premature mortality for this analysis 
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for several reasons: it is the most serious health effect of exposure 

to PM2.5, and EPA has access to nationwide incidence and demographic 

data at an appropriate scale to conduct this type of analysis. EPA 

included educational attainment in this assessment because research 

on the effects of PM2.5 has found that educational attainment is 

inversely related to the risk of all-cause mortality. That is, 

populations with lower levels of education (in particular, less than

grade 12) experience higher rates of PM2.5 mortality. Krewski and 

colleagues127 note in their analysis of this relationship that the 

level of education attainment is likely to be a surrogate for the 

effects of complex socioeconomic processes (including factors such as 

race and income) on mortality.

In the first step of the analysis, we estimated baseline (2005) 

PM2.5 mortality risk by race (White, Black, Asian, Native American) 

among people living in the counties with the highest (top 5 percent) 

PM2.5 mortality risk. We also estimated baseline PM2.5 mortality risk 

by race among people living in the counties with both the highest 

(top 5 percent) poverty rate and the highest (top 5 percent) PM2.5

mortality risk in 2005. And, we estimated the baseline (2005) PM2.5

mortality risk by educational attainment for people living in the 

highest PM2.5 mortality risk counties. In the second step, we 

 

127 Krewski D, Jerrett M, Burnett RT, Ma R, Hughes E, Shi Y, Turner C, 

Pope CA, Thurston G, Calle EE, Thunt MJ. Extended follow-up and 

spatial analysis of the American Cancer Society study linking 

particulate air pollution and mortality. HEI Research Report, 140, 

2009; Health Effects Institute, Boston, MA.
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estimated the changes in risk for different races among the people 

living in these “high-risk” and “high risk and high-poverty” counties 

resulting from implementation of other existing rules in 2014 and 

from implementation of just the Transport Rule in 2014. Finally, in 

the third step, we compared the effects of the Transport Rule by race 

in the high-risk and high risk/high-poverty counties with the effects 

on people (by race) living in all other counties.

In 2005, people living in the highest-risk counties and in the 

high risk/high poverty counties had substantially greater risks of 

PM2.5-related death than people living in the other 95 percent of 

counties. This was true regardless of race: the difference among 

races in both groups of counties was very small and dwarfed by the 

large difference between the two groups of counties for all races. 

For educational attainment, in contrast, our analysis found that 

people with less than high school education had significantly greater 

risks from PM2.5 mortality than people with a greater than high school 

education. This was especially true for people living in the 

highest-risk counties, but also held true for people living in all 

other counties. In summary, in 2005, having less than a high school 

or high school education, living in one of the poorest counties, and 

living in a high air pollution risk county are associated with higher 

PM2.5 mortality risk; race is not.

Our analysis of the effects of the Transport Rule on this 

underlying exposure pattern finds that the rule will significantly 

reduce the PM2.5 mortality among all populations of different races 
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living throughout the U.S. compared to both 2005 and 2014 pre-rule 

(i.e., base case) levels. No group will experience any increases in 

PM2.5 related deaths as a result of implementing the Transport Rule. 

The analysis indicates that the populations with the largest 

improvement (i.e., largest decline) in PM2.5 mortality risk as a 

result of the Transport Rule in 2014 (compared to the base case in 

2014) are people living in the highest-risk counties. Among these 

counties, the largest improvements are for people with less than high 

school or high school education. These reductions in risk within the

highest-risk counties, as well as the reductions in risk within the 

other 95 percent of counties, are distributed among populations of 

different races fairly evenly. Therefore, there is no indication 

that people of particular race receive a greater benefit (or smaller 

benefit) than others. 

The analysis indicates that people living in the high risk/high 

poverty counties will experience larger improvements in risk from the 

Transport Rule compared to their counterparts in the other counties. 

This result suggests that the Transport Rule is providing the 

greatest risk reduction improvements among counties containing the 

poorest, and highest risk, populations. There is also little 

difference in the improvement in risk among races; in other words, 

people in the high risk/high poverty counties experience the same 

improvement in risk regardless of race.

The analysis also indicates that this rule, in conjunction with 

the implementation of existing or proposed rules (e.g., the proposed 
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Mercury and Air Toxics Standards), will reduce the disparity in risk 

between the highest-risk counties and the other 95 percent of 

counties for all races and educational levels. In addition, 

implementation of this Transport Rule and other rules will, together, 

reduce risks in the poorest and highest risk counties to the 

approximate level of risk for the rest of the counties before 

implementation. This analysis is presented in more detail in the RIA 

for this rule which is available in the rule docket No. EPA-HQ-OAR2009-0491 and from the main EPA webpage for the rule at

www.epa.gov/airtransport. 

3. Meaningful Public Participation

EPA defines “Environmental Justice” to include meaningful 

involvement of all people regardless of race, color, national origin, 

or income with respect to the development, implementation, and 

enforcement of environmental laws, regulations, and policies. To 

promote meaningful involvement, EPA developed a communication and 

outreach strategy to ensure that interested communities had access to 

the proposed Transport Rule, were aware of its content, and had an 

opportunity to comment during the comment period. These efforts are 

summarized below. 

As EPA began considering approaches to address the court remand 

of the 2005 Clean Air Interstate Rule, long before the rule was 

proposed, the agency also began gathering input from a large range of 

stakeholders. In the spring of 2009, EPA held a series of listening 

sessions to gather information and perspectives from stakeholders 
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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 titled, “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 Indian 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 the proposal, as they took place prior to its 

development, but they provided valuable information that EPA used in 

developing the proposal.

Just after the rule was proposed in July 2010, EPA presented a 

summary of information related to the proposed Transport Rule at the 

National Environmental Justice Advisory Council (NEJAC) meeting in 

Washington, DC, and responded to questions from NEJAC members 

regarding the proposed rule. EPA also solicited suggestions for how 

to engage environmental justice communities during the rule comment 

period.
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During the public comment period, EPA held public hearings in 

Chicago, Philadelphia, and Atlanta. Each hearing was advertised by 

EPA through a variety of products targeted to general audiences 

(e.g., fact sheets, press release, slide presentation, etc.); on 

EPA’s environmental justice listserve; and by non-profit 

organizations (e.g., American Lung Association). The public hearings 

were held in public buildings (i.e., no formal identification 

required to enter or to speak) and were open for 11 hours (9am -8 pm) 

to accommodate commenters with various work schedules. All three 

hearings were well-attended by members of the general public. During 

hearing breaks, EPA staff spent time talking with individuals, 

including those representing environmental justice organizations or 

communities, to understand their perspectives in greater detail. As 

noted above, several commenters at each hearing made comments related 

to the need to protect communities living near power plants and the 

most vulnerable individuals. Some of these commenters specifically 

mentioned environmental justice; others mentioned issues often of 

concern to environmental justice communities, such as hot spots, 

interest in additional emission reductions and greater environmental 

protection, and concern over the effects of the rule on the most 

sensitive and vulnerable populations.

In September 2010, during the comment period, EPA held a webinar 

for EJ communities on the proposed Transport Rule. A presentation 

tailored for an audience of environmental justice, community, and 

tribal representatives was specifically designed for this webinar. 
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It was sent to registered participants beforehand and put on the 

Transport Rule webpage, where it remains posted. The presentation 

included both information on the context of the rule, plain language 

information describing the rule itself, and directions on how to 

comment on the rule. 

EPA staff made a short presentation and answered questions about 

the Transport Rule on a standing bi-monthly community conference call 

targeted to environmental justice and tribal representatives and 

organizations. In addition, at the fall 2010 NEJAC meeting in Kansas 

City, Missouri, EPA provided details of the proposed Transport Rule 

as part of a larger discussion of a sector-based approach to utility 

regulation.

Regarding tribal consultation, EPA sent letters to all 565 

federally-recognized Tribes in the country offering consultation on 

the proposed Transport Rule. In addition, the January 7 NODA on 

allowance allocation methodologies specifically requested comment on 

allocating allowances to new units in Indian Country. EPA held two 

consultation and information-sharing calls with 16 interested Tribes 

in late January and early February 2011. Tribes participating on 

these consultation and information calls provided comments on the 

proposed rule and the allowance allocation NODA. As noted above, 

this additional input from the consultation process was taken into 

account in the development of the final rule. See Section XII.F for 

more information on tribal consultation.

4. Summary
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EPA believes that the vast majority of communities and 

individuals in areas covered by this rule, including numerous lowincome, minority, and tribal individuals and communities in both 

rural areas and inner cities in the eastern and central U.S., will 

see significant improvements in air quality and resulting 

improvements in health. EPA’s assessment of the effects of the 

proposed and final Transport Rules on these communities included: a) 

the structure of the rule and responses to comments received on 

issues specific to these communities; b) expected SO2 and NOX emission 

reductions; c) expected PM2.5 and ozone air quality improvements; d) 

expected health benefits, including asthma and other health effects 

of particular concern for environmental justice communities; and e) a 

quantitative assessment of the expected socioeconomic distribution of 

a key health benefit (reduction in premature mortality). All of 

these analyses indicate large health and environmental benefits for 

these communities; none shows evidence of adverse effects. As a 

result, EPA concludes that we do not expect disproportionately high 

and adverse human health or environmental effects on minority, lowincome, or tribal populations in the United States as a result of 

implementing this final Transport Rule.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by 

the Small Business Regulatory Enforcement Fairness Act of 1996, 

generally provides that before a rule may take effect, the agency 

promulgating the rule must submit a rule report, which includes a 
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copy of the rule, to each House of the Congress and to the 

Comptroller General of the United States. EPA will submit a report 

containing this rule and other required information to the U.S. 

Senate, the U.S. House of Representatives, and the Comptroller 

General of the United States prior to publication of the rule in the 

Federal Register. A Major rule cannot take effect until 60 days 

after it is published in the Federal Register. This action is a 

‘‘major rule’’ as defined by 5 U.S.C. 804(2). This rule will be 

effective [INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER].

L. Judicial Review

Petitions for judicial review of this action must be filed in 

the United States Court of Appeals for the District of Columbia 

Circuit by [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. Section 307(b)(1) of the CAA indicates which 

Federal Courts of Appeal have venue for petitions of review of final 

actions by EPA. This section provides, in part, that petitions for 

review must be filed in the Court of Appeals for the District of 

Columbia Circuit if (i) the agency action consists of ‘‘nationally 

applicable regulations promulgated, or final action taken, by the 

Administrator,’’ or (ii) such action is locally or regionally 

applicable, if ‘‘such action is based on a determination of 

nationwide scope or effect and if in taking such action the 

Administrator finds and publishes that such action is based on such a 

determination.’’
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Any final action related to the Transport Rule is ‘‘nationally 

applicable’’ within the meaning of section 307(b)(1). Through this 

rule, EPA interprets section 110 of the CAA, a provision which has 

nationwide applicability. In addition, the Transport Rule applies to 

27 States. The Transport Rule is also based on a common core of 

factual findings and analyses concerning the transport of pollutants 

between the different states subject to it. For these reasons, the 

Administrator also is determining that any final action regarding the 

Transport Rule is of nationwide scope and effect for purposes of 

section 307(b)(1). Thus, pursuant to section 307(b) any petitions 

for review of final actions regarding the Transport Rule must be 

filed in the Court of Appeals for the District of Columbia Circuit 

within 60 days from the date final action is published in the Federal 

Register.

Filing a petition for reconsideration of this action does not 

affect the finality of this rule for the purposes of judicial review 

nor does it extend the time within which a petition for judicial 

review may be filed and shall not postpone the effectiveness of such 

rule or action. In addition, pursuant to CAA section 307(b)(2) this 

action may not be challenged later in proceedings to enforce its 

requirements.

 In addition, this action is subject to the provisions of section 

307(d). CAA section 307(d)(1)(B) provides that section 

307(d) applies to, among other things, to "the promulgation or 

revision of an implementation plan by the Administrator under CAA 
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section 110(c)" (42 U.S.C. 7407(d)(1)(B)). The Agency has complied

with procedural requirements of CAA section 307(d) during the course 

of this rulemaking.

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.
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Page 599 of 1285 - Federal Implementation Plans to Reduce Interstate 

Transport of Fine Particulate Matter and Ozone in 27 States; 

Correction of SIP Approvals for 22 States

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

______________________________

Lisa P. Jackson,

Administrator.
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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 

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”. 

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 AAAA through IIII 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:
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(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; 

(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; 

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 
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Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

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 
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(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

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?

* * * * * 
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(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; 

(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;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 
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Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX allowances 

will be required with regard to emissions or excess emissions for 

such control periods.

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
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(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 §§52.38 and 52.39 to read as 

follows: 

§ 52.38 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 set forth in subpart 

AAAAA 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 apply to the 

sources in the following States and Indian country located within the 

borders of such States: Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 

York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 

Virginia, West Virginia, and Wisconsin.

(3) Notwithstanding the provisions of paragraph (a)(1) of this section, a 

State listed in paragraph (a)(2) of this section may adopt and include in a 

SIP revision, and the Administrator will approve, as TR NOX Annual allowance 

allocation provisions replacing the provisions in §97.411(a) of this chapter

with regard to the State and the control period in 2013, a list of TR NOX

Annual units and the amount of TR NOX Annual allowances allocated to each 
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unit on such list, provided that the list of units and allocations meets the 

following requirements:

(i) All of the units on the list must be units that are in the State and

commenced commercial operation before January 1, 2010;

(ii) The total amount of TR NOX Annual allowance allocations on the list 

must not exceed the amount, under §97.410(a) of this chapter for the State 

and the control period in 2013, of TR NOX Annual trading budget minus the 

sum of the new unit set-aside and Indian country new unit set-aside; 

(iii) The list must be submitted electronically in a format specified by the 

Administrator; and

(iv) The SIP revision must not provide for any change in the units and 

allocations on the list after approval of the SIP revision by the 

Administrator and must not provide for any change in any allocation 

determined and recorded by the Administrator under subpart AAAAA of part 97 

of this chapter; 

(v) Provided that:

(A) By [INSERT DATE 70 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER], the 

State must notify the Administrator electronically in a format specified by 

the Administrator of the State’s intent to submit to the Administrator a 

complete SIP revision meeting the requirements of paragraph (a)(3)(i) 

through (iv) of this section by April 1, 2012; and
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(B) The State must submit to the Administrator a complete SIP revision 

described in paragraph (a)(3)(v)(A) of this section by April 1, 2012.

(4) Notwithstanding the provisions of paragraph (a)(1) of this section, a 

State listed in paragraph (a)(2) of this section may adopt and include in a 

SIP revision, and the Administrator will approve, regulations revising 

subpart AAAAA of part 97 of this chapter as follows and not making any other 

substantive revisions of that subpart:

(i) The State may adopt, as TR NOX Annual allowance allocation or auction 

provisions replacing the provisions in §§97.411(a) and (b)(1) and 97.412(a) 

of this chapter with regard to the State and the control period in 2014 or 

any subsequent year, any methodology under which the State or the permitting 

authority allocates or auctions TR NOX Annual allowances, and may adopt, in 

addition to the definitions in §97.402 of this chapter, one or more

definitions that shall apply only to terms as used in the adopted TR NOX

Annual allowance allocation or auction provisions, if such methodology--

(A) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR NOX Annual allowances for any such 

control period not exceeding the amount, under §§97.410(a) and 97.421 of 

this chapter for the State and such control period, of the TR NOX Annual 

trading budget minus the sum of the Indian country new unit set-aside and 

the amount of any TR NOX Annual allowances already allocated and recorded by 

the Administrator. 
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(B) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR NOX Annual allowances for any such control period to any TR 

NOX Annual units covered by §97.411(a) of this chapter, that the State or 

the permitting authority submit such allocations or the results of such 

auctions for such control period (except allocations or results of auctions 

to such units of TR NOX Annual allowances remaining in a set-aside after 

completion of the allocations or auctions for which the set-aside was 

created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

NOX Annual 

allowances are 

allocated or

auctioned

Deadline for

submission of 

allocations or 

auction 

results to 

Administrator

2014 June 1, 2013

2015 June 1, 2013

2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period

(C) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR NOX Annual allowances for any such control period to any TR 

NOX Annual units covered by §§97.411(b)(1) and 97.412(a) of this chapter,
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that the State or the permitting authority submit such allocations or the 

results of such auctions (except allocations or results of auctions to such 

units of TR NOX Annual allowances remaining in a set-aside after completion 

of the allocations or auctions for which the set-aside was created) to the 

Administrator by July 1 of the year of such control period.

(D) Does not provide for any change, after the submission deadlines in 

paragraphs (a)(4)(i)(B) and (C) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart AAAAA of part 97 of this chapter;

(ii) Provided that the State must submit a complete SIP revision meeting the 

requirements of paragraph (a)(4)(i) of this section by December 1 of the 

year before the year of the deadlines for submission of allocations or 

auction results under paragraphs (a)(4)(i)(B) and (C) of this section for 

the first control period for which the State wants to make allocations or 

hold an auction under paragraph (a)(4)(i) of this section.

(5) Notwithstanding the provisions of paragraph (a)(1) of this section, a 

State listed in paragraph (a)(2) of this section may adopt and include in a 

SIP revision, and the Administrator will approve, as correcting in whole or 

in part, as appropriate, the deficiency in the SIP that is the basis for the 

TR Federal Implementation Plan set forth in paragraphs (a)(1) through (4) of 

this section, regulations that are substantively identical to the provisions 

of the TR NOX Annual Trading Program set forth in §§97.402 through 97.435 of 

this chapter, except that the SIP revision:
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(i) May adopt, as TR NOX Annual allowance allocation or auction provisions 

replacing the provisions in §§97.411(a) and (b)(1) and 97.412(a) of this 

chapter with regard to the State and the control period in 2014 or any 

subsequent year, any methodology under which the State or the permitting 

authority allocates or auctions TR NOX Annual allowances and that--

(A) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR NOX Annual allowances for any such 

control period not exceeding the amount, under §§97.410(a) and 97.421 of 

this chapter for the State and such control period, of the TR NOX Annual 

trading budget minus the sum of the Indian country new unit set-aside and 

the amount of any TR NOX Annual allowances already allocated and recorded by 

the Administrator. 

(B) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR NOX Annual allowances for any such control period to any TR 

NOX Annual units covered by §97.411(a) of this chapter, that the State or 

the permitting authority submit such allocations or the results of such 

auctions for such control period (except allocations or results of auctions 

to such units of TR NOX Annual allowances remaining in a set-aside after 

completion of the allocations or auctions for which the set-aside was 

created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

NOX Annual 

Deadline for 

submission of 

allocations or 

auction 
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Page 620 of 1293

allowances are 

allocated or

auctioned

results to 

Administrator

2014 June 1, 2013

2015 June 1, 2013

2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period

(C) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR NOX Annual allowances for any such control period to any TR 

NOX Annual units covered by §§97.411(b)(1) and 97.412(a) of this chapter,

that the State or the permitting authority submit such allocations or the 

results of such auctions (except allocations or results of auctions to such 

units of TR NOX Annual allowances remaining in a set-aside after completion 

of the allocations or auctions for which the set-aside was created) to the 

Administrator by July 1 of the year of such control period.

(D) Does not provide for any change, after the submission deadlines in 

paragraphs (a)(5)(i)(B) and (C) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart AAAAA of part 97 of this chapter; 
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(ii) May adopt, in addition to the definitions in §97.402 of this chapter, 

one or more definitions that shall apply only to terms as used in the TR NOX

Annual allowance allocation or auction provisions adopted under paragraph 

(a)(5)(i) of this section; 

(iii) May substitute the name of the State for the term “State” as used in 

subpart AAAAA of part 97 of this chapter, to the extent the Administrator 

determines that such substitutions do not make substantive changes in the 

provisions in §§97.402 through 97.435 of this chapter; and

(iv) Must not include any of the references to, or requirements imposed on, 

any unit in Indian country within the borders of the State in the provisions 

in §§97.402 through 97.435 of this chapter and must not include the 

provisions in §§97.411(b)(2) and 97.412(b), all of which provisions will 

continue to apply under the portion of the TR Federal Implementation Plan 

that is not replaced by the SIP revision;

(v) Provided that, if and when any covered unit is located in Indian country 

within the borders of the State, the Administrator may modify his or her 

approval of the SIP revision to exclude the provisions in §§97.402 

(definitions of “common designated representative”, “common designated 

representative’s assurance level”, and “common designated representative’s 

share”), 97.406(c)(2), 97.425, and the portions of other provisions 

referencing these sections and may modify the portion of the TR Federal 

Implementation Plan that is not replaced by the SIP revision to include 

these provisions;
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(vi) Provided that the State must submit a complete SIP revision meeting the 

requirements of paragraphs (a)(5)(i) through (iv) of this section by 

December 1 of the year before the year of the deadlines for submission of 

allocations or auction results under paragraphs (a)(5)(i)(B) and (C) of this 

section applicable to the first control period for which the State wants to 

make allocations or hold an auction under paragraphs (a)(5)(i) and (ii) of 

this section. 

(6) Following promulgation of an approval by the Administrator of a State's 

SIP revision as correcting in whole or in part, as appropriate, the SIP’s 

deficiency that is the basis for the TR Federal Implementation Plan 

described in paragraphs (a)(1) through (5) of this section, 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 revision is 

partial or conditional, and will continue to apply to sources in any Indian 

country within the borders of the State.

(7) Notwithstanding the provisions of paragraph (a)(6) of this section, if, 

at the time of such approval of the State's SIP revision, the Administrator 

has already started recording any allocations of TR NOX Annual allowances 

under subpart AAAAA of part 97 of this chapter to units in a State for a 

control period in any year, the provisions of subpart AAAAA of part 97 of 

this chapter authorizing the Administrator to complete the allocation and 

recordation of TR NOX Annual allowances to units in the State for each such 

control period shall continue to apply, unless provided otherwise by such 

approval of the State’s SIP revision.
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(b)(1) The TR NOX Ozone Season Trading Program provisions set forth in 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 apply to 

sources in each of the following States and Indian country located within 

the borders of such States: Alabama, Arkansas, Florida, Georgia, Illinois, 

Indiana, Kentucky, Louisiana, Maryland, Mississippi, New Jersey, New York, 

North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 

Virginia, and West Virginia. 

(3) Notwithstanding the provisions of paragraph (b)(1) of this section, a 

State listed in paragraph (b)(2) of this section may adopt and include in a 

SIP revision, and the Administrator will approve, as TR NOX Ozone Season

allowance allocation provisions replacing the provisions in §97.511(a) of 

this chapter with regard to the State and the control period in 2013, a list 

of TR NOX Ozone Season units and the amount of TR NOX Ozone Season allowances 

allocated to each unit on such list, provided that the list of units and 

allocations meets the following requirements:

(i) All of the units on the list must be units that are in the State and

commenced commercial operation before January 1, 2010;

(ii) The total amount of TR NOX Ozone Season allowance allocations on the 

list must not exceed the amount, under §97.510(a) of this chapter for the 

State and the control period in 2013, of TR NOX Ozone Season trading budget 
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minus the sum of the new unit set-aside and Indian country new unit setaside; 

(iii) The list must be submitted electronically in a format specified by the 

Administrator; and

(iv) The SIP revision must not provide for any change in the units and 

allocations on the list after approval of the SIP revision by the 

Administrator and must not provide for any change in any allocation 

determined and recorded by the Administrator under subpart BBBBB of part 97 

of this chapter; 

(v) Provided that:

(A) By [INSERT DATE 70 DAYS AFTER PUBLICATION IN THE FEDRAL REGISTER], the 

State must notify the Administrator electronically in a format specified by 

the Administrator of the State’s intent to submit to the Administrator a 

complete SIP revision meeting the requirements of paragraph (b)(3)(i) 

through (iv) of this section by April 1, 2012; and

(B) The State must submit to the Administrator a complete SIP revision 

described in paragraph (b)(3)(v)(A) of this section by April 1, 2012. 

(4) Notwithstanding the provisions of paragraph (b)(1) of this section, a 

State listed in paragraph (b)(2) of this section may adopt and include in a 

SIP revision, and the Administrator will approve, regulations revising 
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subpart BBBBB of part 97 of this chapter as follows and not making any other 

substantive revisions of that subpart:

(i) The State may adopt, as applicability provisions replacing the 

provisions in §§97.504(a)(1) and (2) of this chapter, provisions 

substantively identical to those provisions, except that the words “more 

than 25 MWe” are replaced, whenever such words appear, by words specifying a 

uniform lower limit on the amount of megawatts that is not greater than the 

amount specified by the words “more than 25 MWe” and is not less than the 

amount specified by the words “15 MWe or more”; or 

(ii) The State may adopt, as TR NOX Ozone Season allowance allocation or 

auction provisions replacing the provisions in §§97.511(a) and (b)(1) and 

97.512(a) of this chapter with regard to the control period in 2014 or any 

subsequent year, any methodology under which the State or the permitting 

authority allocates or auctions TR NOX Ozone Season allowances, and may 

adopt, in addition to the definitions in §97.502 of this chapter, one or 

more definitions that shall apply only to terms as used in the adopted TR 

NOX Ozone Season allowance allocation or auction provisions, if such 

methodology--

(A) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR NOX Ozone Season allowances for any 

such control period not exceeding the amount, under §§97.510(a) and 97.521

of this chapter for the State and such control period, of the TR NOX Ozone 

Season trading budget minus the sum of the Indian country new unit set-aside
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and the amount of any TR NOX Ozone Season allowances already allocated and 

recorded by the Administrator. 

(B) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR NOX Ozone Season allowances for any such control period to 

any TR NOX Ozone Season units covered by §97.511(a) of this chapter, that 

the State or the permitting authority submit such allocations or the results 

of such auctions for such control period (except allocations or results of 

auctions to such units of TR NOX Ozone Season allowances remaining in a setaside after completion of the allocations or auctions for which the setaside was created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

NOX Ozone 

Season 

allowances are 

allocated or

auctioned

Deadline for 

submission of 

allocations or 

auction 

results to 

Administrator

2014 June 1, 2013

2015 June 1, 2013

2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period
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(C) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR NOX Ozone Season allowances for any such control period to 

any TR NOX Ozone Season units covered by §§97.511(b)(1) and 97.512(a) of 

this chapter, that the State or the permitting authority submit such 

allocations or the results of such auctions (except allocations or results 

of auctions to such units of TR NOX Ozone Season allowances remaining in a 

set-aside after completion of the allocations or auctions for which the setaside was created) to the Administrator by July 1 of the year of such 

control period. 

(D) Does not provide for any change, after the submission deadlines in 

paragraphs (b)(4)(ii)(B) and (C) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart BBBBB of part 97 of this chapter; 

(iii) Provided that the State must submit a complete SIP revision meeting 

the requirements of paragraph (b)(4)(i) or (ii) of this section by December 

1 of the year before the year of the deadlines for submission of allocations 

or auction results under paragraphs (b)(4)(ii)(B) and (C) of this section

applicable to the first control period for which the State wants to replace 

the applicability provisions, make allocations, or hold an auction under 

paragraph (b)(4)(i) or (ii) of this section.

(5) Notwithstanding the provisions of paragraph (b)(1) of this section, a

State listed in paragraph (b)(2) of this section may adopt and include in a 

SIP revision, and the Administrator will approve, as correcting in whole or 
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in part, as appropriate, the deficiency in the SIP that is the basis for the 

TR Federal Implementation Plan set forth in paragraphs (b)(1) through (4) of 

this section, regulations that are substantively identical to the provisions 

of the TR NOX Ozone Season Trading Program set forth in §§97.502 through 

97.535 of this chapter, except that the SIP revision:

(i) May adopt, as applicability provisions replacing the provisions in 

§§97.504(a)(1) and (2) of this chapter, provisions substantively identical 

to those provisions, except that the words “more than 25 MWe” are replaced, 

whenever such words appear, by words specifying a uniform lower limit on the 

amount of megawatts that is not greater than the amount specified by the 

words “more than 25 MWe” and is not less than the amount specified by the 

words “15 MWe or more”; or

(ii) May adopt, as TR NOX Ozone Season allowance allocation provisions 

replacing the provisions in §§97.511(a) and (b)(1) and 97.512(a) of this 

chapter with regard to the control period in 2014 and any subsequent year, 

any methodology under which the State or the permitting authority allocates 

auctions TR NOX Ozone Season allowances and that--

(A) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR NOX Ozone Season allowances for any 

such control period not exceeding the amount, under §§97.510(a) and 97.521

of this chapter for the State and such control period, of the TR NOX Ozone 

Season trading budget minus the sum of the Indian country new unit set-aside

and the amount of any TR NOX Ozone Season allowances already allocated and 

recorded by the Administrator. 
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(B) Requires, to the extent the State adopts provisions for allocations or 

auction of TR NOX Ozone Season allowances for any such control period to any 

TR NOX Ozone Season units covered by §97.511(a) of this chapter, that the 

State or the permitting authority submit such allocations or the results of 

such auctions for such control period (except allocations or results of 

auctions to such units of TR NOX Ozone Season allowances remaining in a setaside after completion of the allocations or auctions for which the setaside was created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

NOX Ozone 

Season 

allowances are 

allocated or

auctioned

Deadline for

submission of 

allocations or 

auction 

results to 

Administrator

2014 June 1, 2013

2015 June 1, 2013

2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period

(C) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR NOX Ozone Season allowances for any control period to any TR 
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NOX Ozone Season units covered by §§97.511(b)(1) and 97.512(a) of this 

chapter, that the State or the permitting authority submit such allocations 

or the results of such auctions (except allocations or results of auctions 

to such units of TR NOX Ozone Season allowances remaining in a set-aside 

after completion of the allocations or auctions for which the set-aside was 

created) to the Administrator by July 1 of the year of such control period. 

(D) Does not provide for any change, after the submission deadlines in 

paragraphs (b)(5)(ii)(B) and (C) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart BBBBB of part 97 of this chapter;

(iii) May adopt in addition to the definitions in §97.502 of this chapter, 

one or more definitions that shall apply only to terms as used in the TR NOX

Ozone Season allowance allocation or auction provisions adopted under 

paragraph (b)(5)(ii) of this section; 

(iv) May substitute the name of the State for the term “State” as used in 

subpart BBBBB of part 97 of this chapter, to the extent the Administrator 

determines that such substitutions do not make substantive changes in the 

provisions in §§97.502 through 97.535 of this chapter; and

(v) Must not include any of the references to, or requirements imposed on, 

any unit in Indian country within the borders of the State in the provisions 

in §§97.502 through 97.535 of this chapter and must not include the 

provisions in §§97.511(b)(2) and 97.512(b), all of which provisions will 
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continue to apply under the portion of the TR Federal Implementation Plan 

that is not replaced by the SIP revision;

(vi) Provided that, if and when any covered unit is located in Indian 

country within the borders of the State, the Administrator may modify his or 

her approval of the SIP revision to exclude the provisions in §§97.502 

(definitions of “common designated representative”, “common designated 

representative’s assurance level”, and “common designated representative’s 

share”), 97.506(c)(2), 97.525, and the portions of other provisions 

referencing these sections and may modify the portion of the TR Federal 

Implementation Plan that is not replaced by the SIP revision to include 

these provisions;

(vii) Provided that the State must submit a complete SIP revision meeting 

the requirements of paragraph (b)(5)(i) through (v) of this section by 

December 1 of the year before the year of the deadlines for submission of 

allocations or auction results under paragraphs (5)(ii)(B) and (C) of this 

section applicable to the first control period for which the State wants to 

replace the applicability provisions, make allocations, or hold an auction

under paragraphs (b)(5)(ii) and (iii) of this section. 

(6) Following promulgation of an approval by the Administrator of a State's 

SIP revision as correcting in whole or in part, as appropriate, the SIP’s 

deficiency that is the basis for the TR Federal Implementation Plan set 

forth in paragraphs (b)(1) through (5) of this section, 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 revision is partial or 
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conditional, and will continue to apply to sources in any Indian country 

within the borders of the State. 

(7) Notwithstanding the provisions of paragraph (b)(6) of this section, if, 

at the time of such approval of the State's SIP revision, the Administrator 

has already started recording any allocations of TR NOX Ozone Season 

allowances under subpart BBBBB of part 97 of this chapter to units in a 

State for a control period in any year, the provisions of subpart BBBBB of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation and recordation of TR NOX Ozone Season allowances to units in the 

State for each such control period shall continue to apply, unless provided 

otherwise by such approval of the State’s SIP revision. 

§ 52.39 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 provisions and the TR SO2 Group 2 

Trading Program provisions set forth respectively in subparts CCCCC and 

DDDDD 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 apply to 

sources in each of the following States and Indian country located within 

the borders of such States: Illinois, Indiana, Iowa, Kentucky, Maryland, 

Michigan, Missouri, New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. 
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(c) The provisions of subpart DDDDD of part 97 of this chapter apply to 

sources in each of the following States and Indian country located within 

the borders of such States: Alabama, Georgia, Kansas, Minnesota, Nebraska, 

South Carolina, and Texas. 

(d) Notwithstanding the provisions of paragraph (a) of this section, a State 

listed in paragraph (b) of this section may adopt and include in a SIP 

revision, and the Administrator will approve, as TR SO2 Group 1 allowance

allocation provisions replacing the provisions in §97.611(a) of this chapter

with regard to the State and the control period in 2013, a list of TR SO2

Group 1 units and the amount of TR SO2 Group 1 allowances allocated to each 

unit on such list, provided that the list of units and allocations meets the 

following requirements:

(1) All of the units on the list must be units that are in the State and

commenced commercial operation before January 1, 2010;

(2) The total amount of TR SO2 Group 1 allowance allocations on the list 

must not exceed the amount, under §97.610(a) of this chapter for the State 

and the control period in 2013, of TR SO2 Group 1 trading budget minus the 

sum of the new unit set-aside and Indian country new unit set-aside; 

(3) The list must be submitted electronically in a format specified by the 

Administrator; and

(4) The SIP revision must not provide for any change in the units and 

allocations on the list after approval of the SIP revision by the 
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Administrator and must not provide for any change in any allocation 

determined and recorded by the Administrator under subpart CCCCC of part 97 

of this chapter; 

(5) Provided that:

(i) By [INSERT DATE 70 DAYS AFTER PUBLICATION IN THE FEDRAL REGISTER], the 

State must notify the Administrator electronically in a format specified by 

the Administrator of the State’s intent to submit to the Administrator a 

complete SIP revision meeting the requirements of paragraph (d)(1) through 

(4) of this section by April 1, 2012; and

(ii) The State must submit to the Administrator a complete SIP revision 

described in paragraph (d)(5)(i) of this section by April 1, 2012.

(e) Notwithstanding the provisions of paragraph (a) of this section, a State 

listed in paragraph (b) of this section may adopt and include in a SIP 

revision, and the Administrator will approve, regulations revising subpart

CCCCC of part 97 of this chapter as follows and not making any other 

substantive revisions of that subpart:

(1) The State may adopt, as TR SO2 Group 1 allowance allocation or auction 

provisions replacing the provisions in §§97.611(a) and (b)(1) and 97.612(a) 

of this chapter with regard to the control period in 2014 or any subsequent 

year, any methodology under which the State or the permitting authority 

allocates or auctions TR SO2 Group 1 allowances and may adopt, in addition 

to the definitions in §97.602 of this chapter, one or more definitions that 
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shall apply only to terms as used in the adopted TR SO2 Group 1 allowance 

allocation or auction provisions, if such methodology--

(i) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR SO2 Group 1 allowances for any such 

control period not exceeding the amount, under §§97.610(a) and 97.621 of 

this chapter for the State and such control period, of the TR SO2 Group 1 

trading budget minus the sum of the Indian country new unit set-aside and 

the amount of any TR SO2 Group 1 allowances already allocated and recorded 

by the Administrator. 

(ii) Requires, to the extent the State adopts provisions for allocations or 

auction of TR SO2 Group 1 allowances for any such control period to any TR 

SO2 Group 1 units covered by §97.611(a) of this chapter, that the State or 

the permitting authority submit such allocations or the results of such 

auctions for such control period (except allocations or results of auctions 

to such units of TR SO2 Group 1 allowances remaining in a set-aside after 

completion of the allocations or auctions for which the set-aside was 

created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

SO2 Group 1 

allowances are 

allocated or

auctioned

Deadline for 

submission of 

allocations or 

auction 

results to 

Administrator

2014 June 1, 2013

2015 June 1, 2013
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2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period

(iii) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR SO2 Group 1 allowances for any such control period to any TR 

SO2 Group 1 units covered by §§97.611(b)(1) and 97.612(a) of this chapter,

that the State or the permitting authority submit such allocations or the 

results of such auctions (except allocations or results of auctions to such 

units of TR SO2 Group 1 allowances remaining in a set-aside after completion 

of the allocations or auctions for which the set-aside was created) to the 

Administrator by July 1 of the year of such control period. 

(iv) Does not provide for any change, after the submission deadlines in 

paragraphs (e)(1)(ii) and (iii) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart CCCCC of part 97 of this chapter; 

(2) Provided that the State must submit a complete SIP revision meeting the 

requirements of paragraph (e)(1) of this section by December 1 of the year 

before the year of the deadlines for submission of allocations or auction 

results under paragraphs (e)(1)(ii) and (iii) of this section applicable to 
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the first control period for which the State wants to make allocations or 

hold an auction under paragraph (e)(1) of this section.

(f) Notwithstanding the provisions of paragraph (a) of this section, a State 

listed in paragraph (b) of this section may adopt and include in a SIP 

revision, and the Administrator will approve, as correcting in whole or in 

part, as appropriate, the deficiency in the SIP that is the basis for the TR 

Federal Implementation Plan set forth in paragraphs (a), (b), (d), and (e) 

of this section, regulations that are substantively identical to the 

provisions of the TR SO2 Group 1 Trading Program set forth in §§97.602 

through 97.635 of this chapter, except that the SIP revision:

(1) May adopt, as TR SO2 Group 1 allowance allocation or auction provisions 

replacing the provisions in §§97.611(a) and (b)(1) and 97.612(a) of this 

chapter with regard to the control period in 2014 and any subsequent year, 

any methodology under which the State or the permitting authority allocates 

or auctions TR SO2 Group 1 allowances and that--

(i) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR SO2 Group 1 allowances for such 

control period not exceeding the amount, under §§97.610(a) and 97.621 of 

this chapter for the State and such control period, of the TR SO2 Group 1 

trading budget minus the sum of the Indian country new unit set-aside and 

the amount of any TR SO2 Group 1 allowances already allocated and recorded 

by the Administrator. 
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(ii) Requires, to the extent the State adopts provisions for allocations or 

auction of TR SO2 Group 1 allowances for any such control period to any TR 

SO2 Group 1 units covered by §97.611(a) of this chapter, that the State or 

the permitting authority submit such allocations or the results of such 

auctions for such control period (except allocations or results of auctions 

to such units of TR SO2 Group 1 allowances remaining in a set-aside after 

completion of the allocations or auctions for which the set-aside was 

created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

SO2 Group 1 

allowances are 

allocated or

auctioned

Deadline for

submission of 

allocations or 

auction 

results to 

Administrator

2014 June 1, 2013

2015 June 1, 2013

2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period

(iii) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR SO2 Group 1 allowances for any such control period to any TR 

SO2 Group 1 units covered by §§97.611(b)(1) and 97.612(a) of this chapter,

that the State or the permitting authority submit such allocations or the 
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results of such auctions (except allocations or results of auctions to such 

units of TR SO2 Group 1 allowances remaining in a set-aside after completion 

of the allocations or auctions for which the set-aside was created) to the 

Administrator by July 1 of the year of such control period.

(iv) Does not provide for any change, after the submission deadlines in 

paragraphs (f)(2)(ii) and (iii) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart CCCCC of part 97 of this chapter;

(2) May adopt, in addition to the definitions in §97.602 of this chapter, 

one or more definitions that shall apply only to terms as used in the TR SO2

Group 1 allowance allocation or auction provisions adopted under paragraph 

(f)(1) of this section; 

(3) May substitute the name of the State for the term “State” as used in 

subpart CCCCC of part 97 of this chapter, to the extent the Administrator 

determines that such substitutions do not make substantive changes in the 

provisions in §§97.602 through 97.635 of this chapter; and

(4) Must not include any of the references to, or requirements imposed on, 

any unit in Indian country within the borders of the State in the provisions 

in §§97.602 through 97.635 of this chapter and must not include the 

provisions in §§97.611(b)(2) and 97.612(b), all of which provisions will 

continue to apply under the portion of the TR Federal Implementation Plan 

that is not replaced by the SIP revision;
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(5) Provided that, if and when any covered unit is located in Indian country 

within the borders of the State, the Administrator may modify his or her 

approval of the SIP revision to exclude the provisions in §§97.602 

(definitions of “common designated representative”, “common designated 

representative’s assurance level”, and “common designated representative’s 

share”), 97.606(c)(2), 97.625, and the portions of other provisions 

referencing these sections and may modify the portion of the TR Federal 

Implementation Plan that is not replaced by the SIP revision to include 

these provisions;

(6) Provided that the State must submit a complete SIP revision meeting the 

requirements of paragraphs (f)(1) through (4) of this section by December 1 

of the year before the year of the deadlines for submission of allocations 

or auction results under paragraphs (f)(1)(ii) and (iii) of this section 

applicable to the first control period for which the State wants to make 

allocations or hold an auction under paragraph (f)(1)(ii) and (iii) of this 

section. 

(g) Notwithstanding the provisions of paragraph (a) of this section, a State 

listed in paragraph (c) of this section may adopt and include in a SIP 

revision, and the Administrator will approve, as TR SO2 Group 2 allowance 

allocation provisions replacing the provisions in §97.711(a) of this chapter

with regard to the control period in 2013, a list of TR SO2 Group 2 units 

and the amount of TR SO2 Group 2 allowances allocated to each unit on such 

list, provided that the list of units and allocations meets the following 

requirements:
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(1) All of the units on the list must be units that are in the State and

commenced commercial operation before January 1, 2010;

(2) The total amount of TR SO2 Group 2 allowance allocations on the list 

must not exceed the amount, under §97.710(a) of this chapter for the State 

and the control period in 2013, of TR SO2 Group 2 trading budget minus the 

sum of the new unit set-aside and Indian country new unit set-aside; 

(3) The list must be submitted electronically in a format specified by the 

Administrator; and

(4) The SIP revision must not provide for any change in the units and 

allocations on the list after approval of the SIP revision by the 

Administrator and must not provide for any change in any allocation 

determined and recorded by the Administrator under subpart DDDDD of part 97 

of this chapter; 

(5) Provided that:

(i) By [INSERT DATE 70 DAYS AFTER PUBLICATION IN THE FEDRAL REGISTER], the 

State must notify the Administrator electronically in a format specified by 

the Administrator of the State’s intent to submit to the Administrator a 

complete SIP revision meeting the requirements of paragraph (g)(1) through 

(4) of this section by April 1, 2012; and 
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(ii) The State must submit to the Administrator a complete SIP revision 

described in paragraph (g)(5)(i) of this section by April 1, 2012. 

(h) Notwithstanding the provisions of paragraph (a) of this section, a State 

listed in paragraph (c) of this section may adopt and include in a SIP 

revision, and the Administrator will approve, regulations revising subpart

DDDDD of part 97 of this chapter as follows and not making any other 

substantive revisions of that subpart:

(1) The State may adopt, as TR SO2 Group 2 allowance allocation or auction 

provisions replacing the provisions in §§97.711(a) and (b)(1) and 97.712(a) 

of this chapter with regard to the control period in 2014 and any subsequent 

year, any methodology under which the State or the permitting authority 

allocates or auctions TR SO2 Group 2 allowances and may adopt, in addition 

to the definitions in §97.702 of this chapter, one or more definitions that 

shall apply only to terms as used in the adopted TR SO2 Group 2 allowance 

allocation or auction provisions, if such methodology—

(i) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR SO2 Group 2 allowances for any such 

control period not exceeding the amount, under §§97.710(a) and 97.721 of 

this chapter for the State and such control period, of the TR SO2 Group 2 

trading budget minus the sum of the Indian country new unit set-aside and 

the amount of any TR SO2 Group 2 allowances already allocated and recorded 

by the Administrator. 
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(ii) Requires, to the extent the State adopts provisions for allocations or 

auction of TR SO2 Group 2 allowances for any such control period to any TR 

SO2 Group 2 units covered by §97.711(a) of this chapter, that the State or 

the permitting authority submit such allocations or the results of such 

auctions for such control period (except allocations or results of auctions 

to such units of TR SO2 Group 2 allowances remaining in a set-aside after 

completion of the allocations or auctions for which the set-aside was 

created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

SO2 Group 2 

allowances are 

allocated or

auctioned

Deadline for

submission of 

allocations or 

auction 

results to 

Administrator

2014 June 1, 2013

2015 June 1, 2013

2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period

(iii) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR SO2 Group 2 allowances for any such control period to any TR 

SO2 Group 2 units covered by §§97.711(b)(1) and 97.712(a) of this chapter,

that the State or the permitting authority submit such allocations or the 
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results of such auctions (except allocations or results of auctions to such 

units of TR SO2 Group 2 allowances remaining in a set-aside after completion 

of the allocations or auctions for which the set-aside was created) to the 

Administrator by July 1 of the year of such control period.

(iv) Does not provide for any change, after the submission deadlines in 

paragraphs (h)(1)(ii) and (iii) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart DDDDD of part 97 of this chapter;

(2) Provided that the State must submit a complete SIP revision meeting the 

requirements of paragraph (h)(1) of this section by December 1 of the year 

before the year of the deadlines for submission of allocations or auction 

results under paragraphs (h)(1)(ii) and (iii) of this section applicable to 

the first control period for which the State wants to make allocations or 

hold an auction under paragraph (h)(1)(ii) and (iii) of this section. 

(i) Notwithstanding the provisions of paragraph (a) of this section, a State 

listed in paragraph (c) of this section may adopt and include in a SIP 

revision, and the Administrator will approve, as correcting in whole or in 

part, as appropriate, the deficiency in the SIP that is the basis for the TR 

Federal Implementation Plan set forth in paragraphs (a), (c), (g), and (h) 

of this section, regulations that are substantively identical to the 

provisions of the TR SO2 Group 2 Trading Program set forth in §§97.702 

through 97.735 of this chapter, except that the SIP revision:
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(1) May adopt, as TR SO2 Group 2 allowance allocation or auction provisions 

replacing the provisions in §§97.711(a) and (b)(1) and 97.712(a) of this 

chapter with regard to the control period in 2014 and any subsequent year, 

any methodology under which the State or the permitting authority allocates 

or auctions TR SO2 Group 2 allowances and that--

(i) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR SO2 Group 2 allowances for any such 

control period not exceeding the amount, under §§97.710(a) and 97.721 of 

this chapter for the State and such control period, of the TR SO2 Group 2 

trading budget minus the sum of the Indian country new unit set-aside and 

the amount of any TR SO2 Group 2 allowances already allocated and recorded 

by the Administrator. 

(ii) Requires, to the extent the State adopts provisions for allocations or 

auction of TR SO2 Group 2 allowances for any such control period to any TR 

SO2 Group 2 units covered by §97.711(a) of this chapter, that the State or 

the permitting authority submit such allocations or the results of such 

auctions for such control period (except allocations or results of auctions 

to such units of TR SO2 Group 1 allowances remaining in a set-aside after 

completion of the allocations or auctions for which the set-aside was

created) to the Administrator no later than the following dates:

Year of the 

control period 

for which TR 

SO2 Group 2 

allowances are 

allocated or

Deadline for 

submission of 

allocations or 

auction 

results to 

Administrator
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auctioned

2014 June 1, 2013

2015 June 1, 2013

2016 June 1, 2014

2017 June 1, 2014

2018 June 1, 2015

2019 June 1, 2015

2020 and any 

year 

thereafter

June 1 of the 

fourth year 

before the 

year of the 

control period

(iii) Requires, to the extent the State adopts provisions for allocations or 

auctions of TR SO2 Group 2 allowances for any such control period to any TR 

SO2 Group 2 units covered by §§97.711(b)(1) and 97.712(a) of this chapter,

that the State or the permitting authority submit such allocations or the 

results of such auctions (except allocations or results of auctions to such 

units of TR SO2 Group 2 allowances remaining in a set-aside after completion 

of the allocations or auctions for which the set-aside was created) to the 

Administrator by July 1 of the year of such control period. 

(iv) Does not provide for any change, after the submission deadlines in 

paragraphs (i)(1)(ii) and (iii) of this section, in the allocations 

submitted to the Administrator by such deadlines and does not provide for 

any change in any allocation determined and recorded by the Administrator 

under subpart DDDDD of part 97 of this chapter;
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(2) May adopt, in addition to the definitions in §97.702 of this chapter, 

one or more definitions that shall apply only to terms as used in the TR SO2

Group 2 allowance allocation or auction provisions adopted under paragraph 

(i)(1) of this section; 

(3) May substitute the name of the State for the term “State” as used in 

subpart DDDDD of part 97 of this chapter, to the extent the Administrator 

determines that such substitutions do not make substantive changes in the 

provisions in §§97.702 through 97.735 of this chapter; and

(4) Must not include any of the references to, or requirements imposed on, 

any unit in Indian country within the borders of the State in the provisions 

in §§97.702 through 97.735 of this chapter and must not include the 

provisions in §§97.711(b)(2) and 97.712(b), all of which provisions will 

continue to apply under the portion of the TR Federal Implementation Plan 

that is not replaced by the SIP revision; 

(5) Provided that, if and when any covered unit is located in Indian country 

within the borders of the State, the Administrator may modify his or her 

approval of the SIP revision to exclude the provisions in §§97.702 

(definitions of “common designated representative”, “common designated 

representative’s assurance level”, and “common designated representative’s 

share”), 97.706(c)(2), 97.725, and the portions of other provisions 

referencing these sections and may modify the portion of the TR Federal 

Implementation Plan that is not replaced by the SIP revision to include 

these provisions;
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(6) Provided that the State must submit a complete SIP revision meeting the 

requirements of paragraphs (i)(1) through (4) of this section by December 1 

of the year before the year of the deadlines for submission of allocations 

or auction results under paragraphs (i)(1)(ii) and (iii) of this section 

applicable to the first control period for which the State wants to make 

allocations or hold an auction under paragraphs (i)(1)(ii) and (iii) of this 

section. 

(j) Following promulgation of an approval by the Administrator of a State's 

SIP revision as correcting in whole or in part, as appropriate, the SIP’s 

deficiency that is the basis for the TR 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 revision is partial or conditional, and will continue to apply to 

sources in any Indian country within the borders of the State.

(k) Notwithstanding the provisions of paragraph (j) of this section, if, at 

the time of such approval of the State's SIP revision, the Administrator has 

already started recording any allocations of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter, or allocations of TR SO2 Group 2

allowances under subpart DDDDD of part 97 of this chapter, to units in a 

State for a control period in any year, the provisions of subpart CCCCC of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation and recordation of TR SO2 Group 1 allowances, or of subpart DDDDD 

of part 97 of this chapter authorizing the Administrator to complete the 

allocation and recordation of TR SO2 Group 2 allowances, as applicable, to 
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units in the State for each such control period shall continue to apply, 

unless provided otherwise by such approval of the State’s SIP revision.

Subpart B—Alabama 

10. Section 52.54 is added to read as follows:

§ 52.54 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Alabama and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Alabama’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Alabama’s SIP revision described in paragraph 

(a)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 
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allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Alabama and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Alabama’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of the Alabama’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

11. Section 52.55 is added to read as follows:
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§ 52.55 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Alabama and for which requirements are set forth under the TR SO2 Group 2 

Trading Program in subpart DDDDD of part 97 of this chapter must comply with 

such requirements. The obligation to comply with such requirements will be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Alabama’s State Implementation Plan (SIP) as correcting the 

SIP’s deficiency that is the basis for the TR Federal Implementation Plan 

under §52.39, except to the extent the Administrator’s approval is partial 

or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Alabama’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 2 allowances under subpart DDDDD of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 2 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart E—Arkansas

12. Section 52.184 is added to read as follows:
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§ 52.184 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a) The owner and operator of each source and each unit located in the State 

of Arkansas and for which requirements are set forth under the TR NOX Ozone 

Season Trading Program in subpart BBBBB of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Arkansas’ State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Arkansas’ SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR NOX Ozone Season allowances under subpart BBBBB of part 97 

of this chapter to units in the State for a control period in any year, the 

provisions of subpart BBBBB of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Ozone 

Season allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart I—Delaware 
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13. 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;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 
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control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 

Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

14. 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,
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(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

15. 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
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(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; 

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 

Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

16. Section 52.485 is amended by designating the introductory text as 

paragraph (a) and adding a new paragraph (b) to read as follows:
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§ 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 K—Florida

17. Section 52.540 is added to read as follows:

§ 52.540 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?
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(a) The owner and operator of each source and each unit located in the State 

of Florida and Indian country within the borders of the State and for which 

requirements are set forth under the TR NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units located in the State will be eliminated by the promulgation of an 

approval by the Administrator of a revision to Florida’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(b), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Florida’s SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Florida’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR NOX Ozone Season allowances under subpart BBBBB of part 97 

of this chapter to units in the State for a control period in any year, the 

provisions of subpart BBBBB of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Ozone 

Season allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart L--Georgia
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18. Section 52.584 is added to read as follows:

§ 52.584 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Georgia and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Georgia’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Georgia’s SIP revision described in paragraph 

(a)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 
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(b)(1) The owner and operator of each source and each unit located in the 

State of Georgia and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Georgia’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Georgia’s SIP revision described in paragraph 

(b)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Ozone Season allowances under subpart BBBBB of part 97 

of this chapter to units in the State for a control period in any year, the 

provisions of subpart BBBBB of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Ozone 

Season allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

19. Section 52.585 is added to read as follows:

§ 52.585 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Georgia and for which requirements are set forth under the TR SO2 Group 2 
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Trading Program in subpart DDDDD of part 97 of this chapter must comply with 

such requirements. The obligation to comply with such requirements will be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Georgia’s State Implementation Plan (SIP) as correcting the 

SIP’s deficiency that is the basis for the TR Federal Implementation Plan 

under §52.39, except to the extent the Administrator’s approval is partial 

or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Georgia’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 2 allowances under subpart DDDDD of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 2

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart O--Illinois

20. Section 52.745 is added to read as follows:

§ 52.745 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?
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(a)(1) The owner and operator of each source and each unit located in the 

State of Illinois and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Illinois’ State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Illinois’ SIP revision described in paragraph 

(a)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Illinois and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Illinois’ State Implementation Plan (SIP) as 
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correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Illinois’ SIP revision described in paragraph 

(b)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Ozone Season allowances under subpart BBBBB of part 97 

of this chapter to units in the State for a control period in any year, the 

provisions of subpart BBBBB of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Ozone 

Season allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

21. Section 52.746 is added to read as follows:

§ 52.746 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Illinois and for which requirements are set forth under the TR SO2 Group 

1 Trading Program in subpart CCCCC of part 97 of this chapter must comply 

with such requirements. The obligation to comply with such requirements 

will be eliminated by the promulgation of an approval by the Administrator 

of a revision to Illinois’ State Implementation Plan (SIP) as correcting the 

SIP’s deficiency that is the basis for the TR Federal Implementation Plan 
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under §52.39, except to the extent the Administrator’s approval is partial 

or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Illinois’ SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart P—Indiana 

22. Section 52.789 is added to read as follows:

§ 52.789 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Indiana and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Indiana’s State Implementation Plan (SIP) as 
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correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Indiana’s SIP revision described in paragraph 

(a)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Indiana and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Indiana’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Indiana’s SIP revision described in paragraph 
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(b)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Ozone Season allowances under subpart BBBBB of part 97 

of this chapter to units in the State for a control period in any year, the 

provisions of subpart BBBBB of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Ozone 

Season allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

23. Section 52.790 is added to read as follows:

§ 52.790 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Indiana and for which requirements are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of part 97 of this chapter must comply with 

such requirements. The obligation to comply with such requirements will be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Indiana’s State Implementation Plan (SIP) as correcting the 

SIP’s deficiency that is the basis for the TR Federal Implementation Plan 

under §52.39 except to the extent the Administrator’s approval is partial or 

conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Indiana’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 
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allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart Q—Iowa

24. Section 52.840 is added to read as follows:

§ 52.840 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Iowa and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by

the Administrator of a revision to Iowa’s State Implementation Plan (SIP) as 

correcting in part the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 
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promulgation of an approval by the Administrator of a revision to Iowa’s 

SIP. 

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Iowa’s SIP revision described in paragraph 

(a)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

(b) [Reserved] 

25. Section 52.841 is added to read as follows:

§ 52.841 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Iowa and Indian country within the borders of the State and for which 

requirements are set forth under the TR SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 
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the Administrator of a revision to Iowa’s State Implementation Plan (SIP) as 

correcting in part the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.39, except to the extent the Administrator’s 

approval is partial or conditional. The obligation to comply with such 

requirements with regard to sources and units located in Indian country 

within the borders of the State will not be eliminated by the promulgation 

of an approval by the Administrator of a revision to Iowa’s SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Iowa’s SIP revision described in paragraph (a) 

of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart R—Kansas

26. Section 52.882 is added to read as follows:

§ 52.882 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?
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(a)(1) The owner and operator of each source and each unit located in the 

State of Kansas and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to Kansas’ State Implementation Plan (SIP) 

as correcting in part the SIP’s deficiency that is the basis for the TR 

Federal Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to Kansas’ 

SIP.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Kansas’ SIP revision described in paragraph 

(a)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

(b)[Reserved] 
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27. Section 52.883 is added to read as follows:

§ 52.883 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Kansas and Indian country within the borders of the State and for which 

requirements are set forth under the TR SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements will be eliminated with 

regard to sources and units in the State by the promulgation of an approval 

by the Administrator of a revision to Kansas’ State Implementation Plan 

(SIP) as correcting in part the SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to Kansas’ 

SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Kansas’ SIP revision described in paragraph (a) 

of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 2 allowances under subpart DDDDD of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 
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Administrator to complete the allocation and recordation of TR SO2 Group 2 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart S--Kentucky

28. Section 52.940 is added to read as follows:

§ 52.940 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Kentucky and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Kentucky’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Kentucky’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 
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year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Kentucky and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Kentucky’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Kentucky’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 
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29. Section 52.941 is added to read as follows:

§ 52.941 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Kentucky and for which requirements are set forth under the TR SO2 Group 

1 Trading Program in subpart CCCCC of part 97 of this chapter must comply 

with such requirements. The obligation to comply with such requirements 

will be eliminated by the promulgation of an approval by the Administrator 

of a revision to Kentucky’s State Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for the TR Federal Implementation 

Plan under §52.39, except to the extent the Administrator’s approval is 

partial or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Kentucky’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart T—Louisiana 
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30. Section 52.984 is amended by adding new paragraphs (c) and (d) 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; 

(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;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 
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control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 

Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

(d)(1) The owner and operator of each source and each unit located in the 

State of Louisiana and Indian country within the borders of the State and 

for which requirements are set forth under the TR NOX Ozone Season Trading 

Program in subpart BBBBB of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to Louisiana’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(b), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Louisiana’s SIP.
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(2) Notwithstanding the provisions of paragraph (d)(1) of this section, if, 

at the time of the approval of Louisiana’s SIP revision described in 

paragraph (d)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

Subpart V—Maryland

31. Section 52.1084 is added to read as follows:

§ 52.1084 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Maryland and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Maryland’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.
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(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Maryland’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Maryland and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Maryland’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Maryland’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 
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in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

32. Section 52.1085 is added to read as follows:

§ 52.1085 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Maryland and for which requirements are set forth under the TR SO2 Group 

1 Trading Program in subpart CCCCC of part 97 of this chapter must comply 

with such requirements. The obligation to comply with such requirements 

will be eliminated by the promulgation of an approval by the Administrator 

of a revision to Maryland’s State Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for the TR Federal Implementation 

Plan under §52.39, except to the extent the Administrator’s approval is 

partial or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Maryland’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 
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Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart X—Michigan 

33. Section 52.1186 is amended by adding new paragraphs (c) and (d) 

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; 
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(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;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 

Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

(d)(1) The owner and operator of each source and each unit located in the 

State of Michigan and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to Michigan’s State Implementation Plan 

(SIP) as correcting in part the SIP’s deficiency that is the basis for the 
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TR Federal Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to Michigan’s 

SIP.

(2) Notwithstanding the provisions of paragraph (d)(1) of this section, if, 

at the time of the approval of Michigan’s SIP revision described in 

paragraph (d)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(e) [Reserved]

34. Section 52.1187 is amended by designating the existing text as 

paragraph (a) and adding new paragraphs (b) and (c) to read as 

follows:

§ 52.1187 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?
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* * * * * 

(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.

(c)(1) The owner and operator of each source and each unit located in the 

State of Michigan and Indian country within the borders of the State and for 

which requirements are set forth under the TR SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to Michigan’s State Implementation Plan 

(SIP) as correcting in part the SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 
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comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to Michigan’s 

SIP.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of Maryland’s SIP revision described in 

paragraph (c)(1) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart Y—Minnesota

35. Section 52.1240 is amended by adding paragraph (c) to read 

as follows:

§ 52.1240 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

* * * * *

(c)(1) The owner and operator of each source and each unit located in the 

State of Minnesota and Indian country within the borders of the State and 
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for which requirements are set forth under the TR NOX Annual Trading Program 

in subpart AAAAA of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to Minnesota’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(a), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Minnesota’s SIP.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of Minnesota’s SIP revision described in 

paragraph (c)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

36. Section 52.1241 is amended by adding paragraph (c) to read 

as follows:
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§ 52.1241 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

* * * * * 

(c)(1) The owner and operator of each source and each unit located in the 

State of Minnesota and Indian country within the borders of the State and 

for which requirements are set forth under the TR SO2 Group 2 Trading 

Program in subpart DDDDD of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to Minnesota’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.39, except to the 

extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Minnesota’s SIP.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of Minnesota’s SIP revision described in 

paragraph (c)(1) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 2 allowances under subpart DDDDD 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart DDDDD of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

2 allowances to units in the State for each such control period shall 
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continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart Z—Mississippi

37. Section 52.1284 is added to read as follows:

§ 52.1284 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a) The owner and operator of each source and each unit located in the State 

of Mississippi and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Ozone Season Trading 

Program in subpart BBBBB of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to Mississippi’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(b), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Mississippi’s SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Mississippi’s SIP revision described in 
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paragraph (a) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

Subpart AA—Missouri

38. Section 52.1341 is added to read as follows:

§ 52.1341 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Missouri and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Missouri’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.
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(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Missouri’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(b) [Reserved]

39. Section 52.1342 is added to read as follows:

§ 52.1342 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Missouri and for which requirements are set forth under the TR SO2 Group 

1 Trading Program in subpart CCCCC of part 97 of this chapter must comply 

with such requirements. The obligation to comply with such requirements 

will be eliminated by the promulgation of an approval by the Administrator 

of a revision to Missouri’s State Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for the TR Federal Implementation 

Plan under §52.39, except to the extent the Administrator’s approval is 

partial or conditional.
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(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Missouri’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart CC—Nebraska

40. Section 52.1428 is added to read as follows:

§ 52.1428 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a) The owner and operator of each source and each unit located in the State 

of Nebraska and Indian country within the borders of the State and for which 

requirements are set forth under the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to Nebraska’s State Implementation Plan 

(SIP) as correcting in part the SIP’s deficiency that is the basis for the 
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TR Federal Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to Nebraska’s 

SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Nebraska’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

41. Section 52.1429 is added to read as follows:

§ 52.1429 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Nebraska and Indian country within the borders of the State and for which 

requirements are set forth under the TR SO2 Group 2 Trading Program in 
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subpart DDDDD of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to Nebraska’s State Implementation Plan 

(SIP) as correcting in part the SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to Nebraska’s 

SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Nebraska’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 2 allowances under subpart DDDDD of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 2 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart FF—New Jersey 

42. Section 52.1584 is amended by adding new paragraphs (c), (d), and 

(e) to read as follows:
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§ 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; 

(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;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 
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(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 

Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

(d)(1) The owner and operator of each source and each unit located in the 

State of New Jersey and for which requirements are set forth under the TR 

NOX Annual Trading Program in subpart AAAAA of part 97 of this chapter must

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to New Jersey’s State Implementation Plan (SIP) 

as correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (d)(1) of this section, if, 

at the time of the approval of New Jersey’s SIP revision described in 

paragraph (d)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 
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Page 695 of 1293

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(e)(1) The owner and operator of each source and each unit located in the 

State of New Jersey and for which requirements are set forth under the TR 

NOX Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to New Jersey’s State Implementation Plan (SIP) 

as correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (e)(1) of this section, if, 

at the time of the approval of New Jersey’s SIP revision described in 

paragraph (e)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

43. Section 52.1585 is amended by designating the existing text as 

paragraph (a) and adding new paragraphs (b) and (c) to read as 

follows:
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§ 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.

(c)(1) The owner and operator of each source and each unit located in the 

State of New Jersey and for which requirements are set forth under the TR 

SO2 Group 1 Trading Program in subpart CCCCC of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to New Jersey’s State Implementation Plan (SIP) 
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as correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.39, except to the extent the Administrator’s 

approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of New Jersey’s SIP revision described in 

paragraph (c)(1) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart HH—New York

44. Section 52.1684 is revised to read as follows:

§ 52.1684 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of New York and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 
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Page 698 of 1293

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to New York’s State Implementation Plan 

(SIP) as correcting in part the SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to New York’s 

SIP.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of New York’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of New York and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Ozone Season Trading 

Program in subpart BBBBB of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 
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Page 699 of 1293

an approval by the Administrator of a revision to New York’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(b), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to New York’s SIP.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of New York’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

45. Section 52.1685 is added to read as follows:

§ 52.1685 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of New York and Indian country within the borders of the State and for which 
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Page 700 of 1293

requirements are set forth under the TR SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to New York’s State Implementation Plan 

(SIP) as correcting in part the SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to New York’s 

SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of New York’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart II—North Carolina

46. Section 52.1784 is revised to read as follows:
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§ 52.1784 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of North Carolina and Indian country within the borders of the State 

and for which requirements are set forth under the TR NOX Annual Trading 

Program in subpart AAAAA of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to North Carolina’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(a), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to North Carolina’s SIP.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of North Carolina’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX
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Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of North Carolina and Indian country within the borders of the State 

and for which requirements are set forth under the TR NOX Ozone Season 

Trading Program in subpart BBBBB of part 97 of this chapter must comply with 

such requirements. The obligation to comply with such requirements with 

regard to sources and units in the State will be eliminated by the 

promulgation of an approval by the Administrator of a revision to North 

Carolina’s State Implementation Plan (SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR Federal Implementation Plan under 

§52.38(b), except to the extent the Administrator’s approval is partial or 

conditional. The obligation to comply with such requirements with regard to 

sources and units located in Indian country within the borders of the State 

will not be eliminated by the promulgation of an approval by the 

Administrator of a revision to North Carolina’s SIP.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of North Carolina’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 
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Page 703 of 1293

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

47. Section 52.1785 is revised to read as follows:

§ 52.1785 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of North Carolina and Indian country within the borders of the State and for 

which requirements are set forth under the TR SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to North Carolina’s State Implementation 

Plan (SIP) as correcting in part the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to North 

Carolina’s SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of North Carolina’s SIP revision described in 

paragraph (a) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 
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of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart KK—Ohio

48. Section 52.1891 is added to read as follows:

§ 52.1891 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Ohio and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Ohio’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Ohio’s SIP revision described in paragraph 

(a)(1) of this section, the Administrator has already started recording any 
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allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Ohio and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Ohio’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Ohio’s SIP revision described in paragraph 

(b)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Ozone Season allowances under subpart BBBBB of part 97 

of this chapter to units in the State for a control period in any year, the 

provisions of subpart BBBBB of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Ozone 

Season allowances to units in the State for each such control period shall 
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continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

49. Section 52.1892 is added to read as follows:

§ 52.1892 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Ohio and for which requirements are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of part 97 of this chapter must comply with 

such requirements. The obligation to comply with such requirements will be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Ohio’s State Implementation Plan (SIP) as correcting the SIP’s 

deficiency that is the basis for the TR Federal Implementation Plan under 

§52.39, except to the extent the Administrator’s approval is partial or 

conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Ohio’s SIP revision described in paragraph (a) 

of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 
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Subpart NN—Pennsylvania

50. Section 52.2040 is added to read as follows:

§ 52.2040 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Pennsylvania and for which requirements are set forth under the TR 

NOX Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Pennsylvania’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency that is the basis for the TR 

Federal Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Pennsylvania’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 
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SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Pennsylvania and for which requirements are set forth under the TR 

NOX Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Pennsylvania’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency that is the basis for the TR 

Federal Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Pennsylvania’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

51. Section 52.2041 is added to read as follows:

§ 52.2041 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?
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(a) The owner and operator of each source and each unit located in the State 

of Pennsylvania and for which requirements are set forth under the TR SO2

Group 1 Trading Program in subpart CCCCC of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Pennsylvania’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency that is the basis for the TR 

Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Pennsylvania’s SIP revision described in 

paragraph (a) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart PP—South Carolina

52. Section 52.2140 is revised to read as follows:
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§ 52.2140 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of South Carolina and Indian country within the borders of the State 

and for which requirements are set forth under the TR NOX Annual Trading 

Program in subpart AAAAA of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to South Carolina’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(a), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to South Carolina’s SIP.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of South Carolina’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 
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SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of South Carolina and Indian country within the borders of the State 

and for which requirements are set forth under the TR NOX Ozone Season 

Trading Program in subpart BBBBB of part 97 of this chapter must comply with 

such requirements. The obligation to comply with such requirements with 

regard to sources and units in the State will be eliminated by the 

promulgation of an approval by the Administrator of a revision to South 

Carolina’s State Implementation Plan (SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR Federal Implementation Plan under 

§52.38(b), except to the extent the Administrator’s approval is partial or 

conditional. The obligation to comply with such requirements with regard to 

sources and units located in Indian country within the borders of the State 

will not be eliminated by the promulgation of an approval by the 

Administrator of a revision to South Carolina’s SIP.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of South Carolina’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 
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53. Section 52.2141 is revised to read as follows:

§ 52.2141 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of South Carolina and Indian country within the borders of the State and for 

which requirements are set forth under the TR SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to South Carolina’s State Implementation 

Plan (SIP) as correcting in part the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to South 

Carolina’s SIP.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of South Carolina’s SIP revision described in 

paragraph (a) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 
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the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart RR—Tennessee 

54. Section 52.2240 is amended by adding new paragraphs (c), (d), and 

(e) 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
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(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;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 

Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

(d)(1) The owner and operator of each source and each unit located in the 

State of Tennessee and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Tennessee’s State Implementation Plan (SIP) 

as correcting the SIP’s deficiency that is the basis for the TR Federal 
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Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the

promulgation of an approval by the Administrator of a revision to 

Tennessee’s SIP.

(2) Notwithstanding the provisions of paragraph (d)(1) of this section, if, 

at the time of the approval of Tennessee’s SIP revision described in 

paragraph (d)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(e)(1) The owner and operator of each source and each unit located in the 

State of Tennessee and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Tennessee’s State Implementation Plan (SIP) 

as correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 
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Page 716 of 1293

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to 

Tennessee’s SIP.

(2) Notwithstanding the provisions of paragraph (e)(1) of this section, if, 

at the time of the approval of Tennessee’s SIP revision described in 

paragraph (e)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

55. Section 52.2241 is amended by designating the existing text as 

paragraph (a) and adding new paragraphs (b) and (c) to read as 

follows:

§ 52.2241 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

* * * * * 
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(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.

(c)(1) The owner and operator of each source and each unit located in the 

State of Tennessee and for which requirements are set forth under the TR SO2

Group 1 Trading Program in subpart CCCCC of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Tennessee’s State Implementation Plan (SIP) 

as correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.39, except to the extent the Administrator’s 

approval is partial or conditional. The obligation to comply with such 

requirements with regard to sources and units located in Indian country 
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Page 718 of 1293

within the borders of the State will not be eliminated by the promulgation 

of an approval by the Administrator of a revision to Tennessee’s SIP.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of Tennessee’s SIP revision described in 

paragraph (c)(1) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart SS—Texas 

56. Section 52.2283 is amended by revising paragraph (b) and adding 

new paragraphs (c) and (d) to read as follows:

§ 52.2283 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

* * * * *

(b) Notwithstanding any provisions of paragraph (a) of this section 

and subparts AA through II of part 97 of this chapter to the 

contrary: 
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(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; 

(2) The Administrator will not deduct for excess emissions any CAIR 

NOX allowances allocated for 2012 or any year thereafter;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods. 

(c)(1) The owner and operator of each source and each unit located in the 

State of Texas and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to Texas’ State Implementation Plan (SIP) as 

correcting in part the SIP’s deficiency that is the basis for the TR Federal 
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Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional. The obligation to 

comply with such requirements with regard to sources and units located in 

Indian country within the borders of the State will not be eliminated by the 

promulgation of an approval by the Administrator of a revision to Texas’ 

SIP.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of Texas’ SIP revision described in paragraph 

(c)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Annual allowances under subpart AAAAA of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart AAAAA of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Annual 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision.

(d)(1) The owner and operator of each source and each unit located in the 

State of Texas and Indian country within the borders of the State and for 

which requirements are set forth under the TR NOX Ozone Season Trading 

Program in subpart BBBBB of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to Texas’ State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38(b), except to 
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Page 721 of 1293

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Texas’ SIP.

(2) Notwithstanding the provisions of paragraph (d)(1) of this section, if, 

at the time of the approval of Texas’ SIP revision described in paragraph 

(d)(1) of this section, the Administrator has already started recording any 

allocations of TR NOX Ozone Season allowances under subpart BBBBB of part 97 

of this chapter to units in the State for a control period in any year, the 

provisions of subpart BBBBB of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR NOX Ozone 

Season allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

57. Section 52.2284 is amended by designating the existing text as 

paragraph (a) and adding new paragraphs (b) and (c) to read as 

follows:

§ 52.2284 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

* * * * * 
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(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.

(c)(1) The owner and operator of each source and each unit located in the 

State of Texas and Indian country within the borders of the State and for 

which requirements are set forth under the TR SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this chapter must comply with such requirements. 

The obligation to comply with such requirements with regard to sources and 

units in the State will be eliminated by the promulgation of an approval by 

the Administrator of a revision to Texas’ State Implementation Plan (SIP) as 

correcting in part the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.39, except to the extent the Administrator’s 

approval is partial or conditional. The obligation to comply with such 

requirements with regard to sources and units located in Indian country 
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Page 723 of 1293

within the borders of the State will not be eliminated by the promulgation 

of an approval by the Administrator of a revision to Texas’ SIP.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of Texas’ SIP revision described in paragraph 

(c)(1) of this section, the Administrator has already started recording any 

allocations of TR SO2 Group 2 allowances under subpart DDDDD of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 2 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart VV—Virginia

58. Section 52.2440 is added to read as follows:

§ 52.2440 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of Virginia and for which requirements are set forth under the TR NOX

Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Virginia’s State Implementation Plan (SIP) as 
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Page 724 of 1293

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of Virginia’s SIP revision described in 

paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of Virginia and for which requirements are set forth under the TR NOX

Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to Virginia’s State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is the basis for the TR Federal 

Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of Virginia’s SIP revision described in 
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paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 

period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

59. Section 52.2241 is added to read as follows:

§ 52.2241 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of Virginia and for which requirements are set forth under the TR SO2 Group 

1 Trading Program in subpart CCCCC of part 97 of this chapter must comply 

with such requirements. The obligation to comply with such requirements 

will be eliminated by the promulgation of an approval by the Administrator 

of a revision to Virginia’s State Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for the TR Federal Implementation 

Plan under §52.39, except to the extent the Administrator’s approval is 

partial or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of Virginia’s SIP revision described in paragraph 

(a) of this section, the Administrator has already started recording any 
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allocations of TR SO2 Group 1 allowances under subpart CCCCC of part 97 of 

this chapter to units in the State for a control period in any year, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation and recordation of TR SO2 Group 1 

allowances to units in the State for each such control period shall continue 

to apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

Subpart XX—West Virginia

60. Section 52.2540 is added to read as follows:

§ 52.2540 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

(a)(1) The owner and operator of each source and each unit located in the 

State of West Virginia and for which requirements are set forth under the TR 

NOX Annual Trading Program in subpart AAAAA of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to West Virginia’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency that is the basis for the TR 

Federal Implementation Plan under §52.38(a), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (a)(1) of this section, if, 

at the time of the approval of West Virginia’s SIP revision described in 
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paragraph (a)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(b)(1) The owner and operator of each source and each unit located in the 

State of West Virginia and for which requirements are set forth under the TR 

NOX Ozone Season Trading Program in subpart BBBBB of part 97 of this chapter 

must comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to West Virginia’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency that is the basis for the TR 

Federal Implementation Plan under §52.38(b), except to the extent the 

Administrator’s approval is partial or conditional.

(2) Notwithstanding the provisions of paragraph (b)(1) of this section, if, 

at the time of the approval of West Virginia’s SIP revision described in 

paragraph (b)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Ozone Season allowances under subpart 

BBBBB of part 97 of this chapter to units in the State for a control period 

in any year, the provisions of subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to complete the allocation and recordation of 

TR NOX Ozone Season allowances to units in the State for each such control 
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period shall continue to apply, unless provided otherwise by such approval 

of the State’s SIP revision. 

61. Section 52.2541 is added to read as follows:

§ 52.2541 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

(a) The owner and operator of each source and each unit located in the State 

of West Virginia and for which requirements are set forth under the TR SO2

Group 1 Trading Program in subpart CCCCC of part 97 of this chapter must 

comply with such requirements. The obligation to comply with such 

requirements will be eliminated by the promulgation of an approval by the 

Administrator of a revision to West Virginia’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency that is the basis for the TR 

Federal Implementation Plan under §52.39, except to the extent the 

Administrator’s approval is partial or conditional.

(b) Notwithstanding the provisions of paragraph (a) of this section, if, at 

the time of the approval of West Virginia’s SIP revision described in 

paragraph (a) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall 
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Page 729 of 1293

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

Subpart YY—Wisconsin 

62. Section 52.2587 is amended by adding new paragraphs (c) and (d)

to read as follows:

§ 52.2587 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
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(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;

(3) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Allowance 

Tracking System accounts all CAIR NOX allowances allocated for a 

control period in 2012 and any subsequent year, and, thereafter, no 

holding or surrender of CAIR NOX allowances will be required with 

regard to emissions or excess emissions for such control periods; and 

(4) By [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will remove from the CAIR NOX Ozone 

Season Allowance Tracking System accounts all CAIR NOX Ozone Season 

allowances allocated for a control period in 2012 and any subsequent 

year, and, thereafter, no holding or surrender of CAIR NOX Ozone 

Season allowances will be required with regard to emissions or excess 

emissions for such control periods.

(d)(1) The owner and operator of each source and each unit located in the 

State of Wisconsin and Indian country within the borders of the State and 

for which requirements are set forth under the TR NOX Annual Trading Program 

in subpart AAAAA of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to Wisconsin’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 
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Page 731 of 1293

the basis for the TR Federal Implementation Plan under §52.38(a), except to 

the extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Wisconsin’s SIP.

(2) Notwithstanding the provisions of paragraph (d)(1) of this section, if, 

at the time of the approval of Wisconsin’s SIP revision described in 

paragraph (d)(1) of this section, the Administrator has already started 

recording any allocations of TR NOX Annual allowances under subpart AAAAA of 

part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart AAAAA of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR NOX

Annual allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision.

(e) [Reserved] 

63. Section 52.2588 is amended by designating the existing text as 

paragraph (a) and adding new paragraphs (b) and (c) to read as 

follows:

§ 52.2588 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?
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* * * * * 

(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.

(c)(1) The owner and operator of each source and each unit located in the 

State of Wisconsin and Indian country within the borders of the State and 

for which requirements are set forth under the TR SO2 Group 1 Trading 

Program in subpart CCCCC of part 97 of this chapter must comply with such 

requirements. The obligation to comply with such requirements with regard 

to sources and units in the State will be eliminated by the promulgation of 

an approval by the Administrator of a revision to Wisconsin’s State 

Implementation Plan (SIP) as correcting in part the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.39, except to the 
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extent the Administrator’s approval is partial or conditional. The 

obligation to comply with such requirements with regard to sources and units 

located in Indian country within the borders of the State will not be 

eliminated by the promulgation of an approval by the Administrator of a 

revision to Wisconsin’s SIP.

(2) Notwithstanding the provisions of paragraph (c)(1) of this section, if, 

at the time of the approval of Wisconsin’s SIP revision described in 

paragraph (c)(1) of this section, the Administrator has already started 

recording any allocations of TR SO2 Group 1 allowances under subpart CCCCC 

of part 97 of this chapter to units in the State for a control period in any 

year, the provisions of subpart CCCCC of part 97 of this chapter authorizing 

the Administrator to complete the allocation and recordation of TR SO2 Group 

1 allowances to units in the State for each such control period shall 

continue to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

PART 72—[AMENDED]

64. 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]

65. Section 72.2 is amended by removing the definition of “Interested 

person”. 

PART 78—[AMENDED]
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66. The authority citation for Part 78 continues to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et seq.

67. 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. 
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(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. 

(14) Under subpart BBBBB of part 97 of this chapter,

(i) The decision on allocation of TR NOX Ozone Season 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. 

(15) Under subpart CCCCC of part 97 of this chapter,
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(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. 

(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.
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(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. 

* * * * * 

68. 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:
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(i) 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;

(ii) Who submitted objections pursuant to an opportunity for 

objections provided by the Administrator as part of the process of 

making such decision; or

(iii) Who submitted, to the Administrator and in a format prescribed 

by the Administrator, his or her name, service address, telephone 

number, and facsimile number and identified such decision in order to 

be placed on a list of persons interested in such decision;

(iv) Provided that 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 
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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 same-day 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.

69. 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) * * * 
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(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.

* * * * * 

70. Section 78.4 is amended by:

a. Revising paragraph (a) by:

i. Removing the first, second, third, fourth, fifth, and last 

sentences; 

ii. In the sixth and seventh sentences, removing the words “interest 

in” and adding, in their place, the words “ownership interest with 

respect to”; 
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iii. Redesignating the paragraph as paragraph (a)(1)(iii); and

b. Adding paragraphs (a)(1) introductory text, (a)(1)(i), and 

(a)(1)(ii); and 

c. Revising paragraph (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 
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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. 

* * * * * 

§ 78.5 [Amended]

71. Section 78.5 is amended by, in paragraph (a):

a. Removing the words “public comment prior to” and adding, in their 

place, the words “submission of public comments or objections prior 

to”;

b. Removing the words “public comment period” whenever they appear 

and adding, in their place, the words “period for submission of 

public comments or objections”. 

§ 78.12 [Amended]

72. Section 78.12 is amended by, in paragraph (a), removing the words 

“public comment” and adding, in their place, the words “submission of 

public comments or objections”. 

PART 97-[Amended]
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73. 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.

74. Part 97 is amended by adding subpart AAAAA to read as follows:

Subpart AAAAA—TR NOX Annual Trading Program 

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 setasides, Indian country new unit set-asides and variability limits.

97.411 Timing requirements for TR NOX Annual allowance allocations.

97.412 TR NOX Annual allowance allocations to new units.
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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 compliance accounts and general 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.
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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.

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 

§52.38 of this chapter, as a means of mitigating interstate transport 

of fine particulates and nitrogen oxides.
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§ 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 multi-state 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 determined by the Administrator) 

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, State, or permitting 

authority, in accordance with this subpart and any SIP revision 

submitted by the State and approved by the Administrator under 

§52.38(a)(3), (4), or (5) of this chapter, of the amount of such TR 

NOX Annual allowances to be initially credited, at no cost to the 

recipient, to:

(1) A TR NOX Annual unit;

(2) A new unit set-aside;
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(3) An Indian country new unit set-aside; or

(4) An entity not listed in paragraphs (1) through (3) of this 

definition;

(5) Provided that, if the Administrator, State, or permitting 

authority initially credits, to a TR NOX Annual unit qualifying for an 

initial credit, a credit in the amount of zero TR NOX Annual 

allowances, the TR NOX Annual unit will be treated as being allocated 

an amount (i.e., zero) of TR NOX Annual allowances. 

Allowable NOX emission rate means, for a unit, the most stringent 

State or federal NOX emission rate limit (in lb/MWhr or, if in 

lb/mmBtu, converted to lb/MWhr by multiplying it by the unit’s heat 

rate in mmBtu/MWhr) 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, recorded, held, deducted, or transferred 

only as whole allowances. 

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.
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Allowance transfer deadline means, for a control period in a given 

year, 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 submitted for recordation in 

a TR NOX 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 §§97.406 and 

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 the respective program. 

Assurance account means an Allowance Management System account, 

established by the Administrator under §97.425(b)(3) for certain 

owners and operators of a group of one or more TR NOX Annual sources 

and units in a given State (and Indian country within the borders of 

such State), in which are held TR NOX Annual allowances available for 
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use for a control period in a given year in complying with the TR NOX

Annual assurance provisions in accordance with §§97.406 and 97.425. 

Authorized account representative means, for 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, for 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
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(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 pressuretreated, 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.

Business day means a day that does not fall on a weekend or a federal 

holiday.

Certifying official means a natural person who is:
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(1) For a corporation, a president, secretary, treasurer, or vicepresident of 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 “coal” as defined in §72.2 of this chapter.

Coal-derived fuel means any fuel (whether in a solid, liquid, or 

gaseous state) produced by the mechanical, thermal, or chemical 

processing of coal.

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 that is a toppingcycle unit or a bottoming-cycle unit:
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(1) Operating as part of a cogeneration system; and

(2) Producing on an annual average basis—

(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 than 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 requirements in paragraph (2) of this 

definition shall not apply to a calendar year referenced in paragraph 

(2) of this definition during which the unit did not operate at all;

(4) 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
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(5) Provided that, if, throughout its operation during the 12-month 

period or a calendar year referenced in paragraph (2) of this 

definition, a unit is operated as part of a cogeneration system and 

the cogeneration system meets on a system-wide basis the requirement 

in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall 

be deemed to meet such requirement during that 12-month period or 

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 January 1, 2005 or the date the unit commences commercial 
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operation as defined in the introductory text of paragraph (1) of 

this definition and that subsequently undergoes a physical change or 

is moved to a new location or 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 January 1, 2005 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 or a different 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 §97.405, for a unit that is not a TR NOX Annual unit under 

§97.404 on the later of January 1, 2005 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 
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definition and that subsequently undergoes a physical change or is 

moved to a different location or 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 or 

a different 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.

Common designated representative means, with regard to a control 

period in a given year, a designated representative where, as of 

April 1 immediately after the allowance transfer deadline for such 

control period, the same natural person is authorized under 

§§97.413(a) and 97.415(a) as the designated representative for a 

group of one or more TR NOX Annual sources and units located in a 

State (and Indian country within the borders of such State).

Common designated representative’s assurance level means, with regard 

to a specific common designated representative and a State (and 

Indian country within the borders of such State) and control period 

in a given year for which the State assurance level is exceeded as 
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described in §97.406(c)(2)(iii), the common designated 

representative’s share of the State NOX Annual trading budget with the 

variability limit for the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative for a control period in a 

given year:

(1) With regard to a total amount of NOX emissions from all TR NOX

Annual units in a State (and Indian country within the borders of 

such State) during such control period, the total tonnage of NOX

emissions during such control period from a group of one or more TR 

NOX Annual units located in such State (and such Indian country) and 

having the common designated representative for such control period; 

(2) With regard to a State NOX Annual trading budget with the 

variability limit for such control period, the amount (rounded to the 

nearest allowance) equal to the sum of the total amount of TR NOX

Annual allowances allocated for such control period to a group of one 

or more TR NOX Annual units located in the State (and Indian country 

within the borders of such State) and having the common designated 

representative for such control period and of the total amount of TR 

NOX Annual allowances purchased by an owner or operator of such TR NOX

Annual units in an auction for such control period and submitted by 

the State or the permitting authority to the Administrator for 

recordation in the compliance accounts for such TR NOX Annual units in 
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accordance with the TR NOX Annual allowance auction provisions in a 

SIP revision approved by the Administrator under §52.38(a)(4) or (5) 

of this chapter, multiplied by the sum of the State NOX Annual trading 

budget under §97.410(a) and the State’s variability limit under 

§97.410(b) for such control period and divided by such State NOX

Annual trading budget; 

(3) Provided that, in the case of a unit that operates during, but 

has no amount of TR NOX Annual allowances allocated under §§97.411 and 

97.412 for, such 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 unit’s allowable NOX emission rate 

applicable to such control period, multiplied by a capacity factor of 

0.85 (if the unit is a boiler combusting any amount of coal or coalderived fuel during such control period), 0.24 (if the unit is a 

simple combustion turbine during such control period), 0.67 (if the 

unit is a combined cycle turbine during such control period), 0.74 

(if the unit is an integrated coal gasification combined cycle unit 

during such control period), or 0.36 (for any other unit), 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. 

Common stack means a single flue through which emissions from 2 or 

more units are exhausted.
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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 to 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 a 

given year in complying with the source's TR NOX Annual emissions 

limitation in accordance with §§97.406 and 97.424. 

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 
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handling system and providing a permanent, continuous record of NOX

emissions, in parts per million (ppm);

(3) A NOX emission rate (or NOX-diluent) 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.
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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 the respective program. 

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:

(1) In accordance with this subpart; and

(2) With regard to a period before the unit or source is required to 

measure, record, and report such air pollutants in accordance with 

this subpart, in accordance with part 75 of this chapter.
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Excess emissions means any ton of emissions from the TR NOX Annual 

units at a TR NOX Annual source during a control period in a given 

year that exceeds the TR NOX Annual emissions limitation for the 

source for such control period.

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 the limitation on “average annual fuel 

consumption of fossil fuel” in §§97.404(b)(2)(i)(B) and (ii), 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 2005 or any calendar year thereafter.

General account means an Allowance Management System account, 

established under this subpart, that is not a compliance account or 

an assurance account.

Generator means a device that produces electricity.

Gross electrical output means, for 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 
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processing or treatment of fuel combusted at the unit and any on-site 

emission controls).

Heat input means, for a unit for a specified period of time, the 

product (in mmBtu/time) of the gross calorific value of the fuel (in 

mmBtu/lb) fed into the unit multiplied by the fuel feed rate (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, for a unit, the amount of heat input (in 

mmBtu) divided by unit operating time (in hr) or, for a unit and 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.

Heat rate means, for a unit, the unit’s maximum design heat input (in 

Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the unit’s 

maximum hourly load.

Indian country means “Indian country” as defined in 18 U.S.C. 1151.

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 
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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, for a unit, the maximum amount of 

fuel per hour (in Btu/hr) that the 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, rounded 
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to the nearest tenth) 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 

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 (in MWe, rounded to 

the nearest tenth) as of such completion as specified by the person 

conducting the physical change.

Natural gas means “natural gas” as defined in §72.2 of this chapter.

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, for a TR NOX Annual source or a TR NOX Annual unit at 

a source respectively, any person who operates, controls, or 

supervises a TR NOX Annual unit at the source or the TR NOX Annual 

unit and shall include, but not be limited to, any holding company, 

utility system, or plant manager of such source or unit.
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Owner means, for 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; 

and(3) Any purchaser of power from a TR NOX Annual unit at the source 

or the TR NOX Annual unit under a life-of-the-unit, firm power 

contractual arrangement. 

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, for a unit, 33 percent of 

the 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.
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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, auction, 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) The use of reject heat from electricity production in a useful 

thermal energy application or process; or
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(2) 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 that is subject to the TR NOX Annual 

Trading Program pursuant to §52.38(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;
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(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, for a unit, total energy of all forms 

supplied to the 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.
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Total energy output means, for a unit, the sum of useful power and 

useful thermal energy produced by the unit.

TR NOX Annual allowance means a limited authorization issued and 

allocated or auctioned by the Administrator under this subpart, or by 

a State or permitting authority under a SIP revision approved by the 

Administrator under §52.38(a)(3), (4), or (5) of this chapter, to 

emit one ton of NOX during a control period of the specified calendar 

year for which the authorization is allocated or auctioned or of any 

calendar year thereafter under the TR NOX Annual Trading 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 from an 

assurance account (e.g., in order to account for compliance with the 

assurance provisions under §§97.406 and 97.425). 

TR NOX Annual allowances held or hold TR NOX Annual allowances means 

the TR NOX Annual 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 
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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 emissions limitation means, for a TR NOX Annual source, 

the tonnage of NOX emissions authorized in a control period in a given 

year 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 Trading Program means a multi-state NOX air pollution 

control and emission reduction program established in accordance with 

this subpart and §52.38(a) of this chapter (including such a program 

that is revised in a SIP revision approved by the Administrator under 

§52.38(a)(3) or (4) of this chapter or that is established in a SIP 

revision approved by the Administrator under §52.38(a)(5) of this 

chapter), as a means of mitigating interstate transport of fine 

particulates and NOX.

TR NOX Annual unit means a unit that is subject to the TR NOX Annual 

Trading Program.
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TR NOX Ozone Season Trading Program means a multi-state NOX air 

pollution control and emission reduction program established in 

accordance with subpart BBBBB of this part and §52.38(b) of this 

chapter (including such a program that is revised in a SIP revision 

approved by the Administrator under §52.38(b)(3) or (4) of this 

chapter or that is established in a SIP revision approved by the 

Administrator under §52.38(b)(5) 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 in accordance with 

subpart CCCCC of this part and §52.39(a), (b), (d) through (f), (j), 

and (k) of this chapter (including such a program that is revised in 

a SIP revision approved by the Administrator under §52.39(d) or (e) 

of this chapter or that is established in a SIP revision approved by 

the Administrator under §52.39(f) 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 in accordance with 

subpart DDDDD of this part and 52.39(a), (c), and (g) through (k) of 

this chapter (including such a program that is revised in a SIP 

revision approved by the Administrator under §52.39(g) or (h) of this 

chapter or that is established in a SIP revision approved by the 

Administrator under §52.39(i) of this chapter), as a means of 

mitigating interstate transport of fine particulates and SO2.
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Unit means a stationary, fossil-fuel-fired boiler, stationary, 

fossil-fuel-fired combustion turbine, or other stationary, fossilfuel-fired combustion device. A unit that undergoes a physical 

change or is moved to a different location or source shall continue

to be treated as the same unit. A unit (the replaced unit) that is 

replaced by another unit (the replacement unit) at the same or a 

different source shall continue to be treated as the same unit, and 

the replacement unit shall be treated as a separate unit.

Unit operating day means, with regard to a unit, a calendar day in 

which the unit combusts any fuel.

Unit operating hour or hour of unit operation means, with regard to a 

unit, an hour in which the unit combusts any fuel.

Useful power means, with regard to a unit, electricity or mechanical 

energy that the 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;
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(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
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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 (and Indian country within the 

borders of such 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, fossilfuel-fired boiler or stationary, fossil-fuel-fired combustion turbine 

serving at any time, on or after January 1, 2005, a generator with 

nameplate capacity of more than 25 MWe producing electricity for 

sale.
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(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 (and Indian country within the borders of 

such 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) or (2)(i) of this section shall not be a TR NOX

Annual unit:

(1)(i) Any unit:

(A) Qualifying as a cogeneration unit throughout the later of 2005 or 

the 12-month period starting on the date the unit first produces 

electricity and continuing to qualify as a cogeneration unit

throughout each calendar year ending after the later of 2005 or such 

12-month period; and

(B) Not supplying in 2005 or any calendar year thereafter 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.
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(ii) If, after qualifying under paragraph (b)(1)(i) of this section 

as not being a TR NOX Annual unit, a unit subsequently no longer meets 

all the requirements of paragraph (b)(1)(i) of this section, 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. The unit shall thereafter 

continue to be a TR NOX Annual unit.

(2)(i) Any unit:

(A) Qualifying as a solid waste incineration unit throughout the 

later of 2005 or the 12-month period starting on the date the unit 

first produces electricity and continuing to qualify as a solid waste 

incineration unit throughout each calendar year ending after the 

later of 2005 or such 12-month period; and

(B) With an average annual fuel consumption of fossil fuel for the 

first 3 consecutive calendar years of operation starting no earlier 

than 2005 of less than 20 percent (on a Btu basis) and an average 

annual fuel consumption of fossil fuel for any 3 consecutive calendar 

years thereafter of less than 20 percent (on a Btu basis).

(ii) If, after qualifying under paragraph (b)(2)(i) of this section 

as not being a TR NOX Annual unit, a unit subsequently no longer meets 
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all the requirements of paragraph (b)(1)(i) of this section, 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 2005 for which the unit has 

an average annual fuel consumption of fossil fuel of 20 percent or 

more. The unit shall thereafter continue to be a TR NOX Annual unit.

(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 or a SIP revision approved under §52.38(a)(4) or (5) of this 

chapter, 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 
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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 State or 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 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 
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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.
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(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 
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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 in a given year, 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 total NOX emissions during a control period in a given year 

from the TR NOX Annual units at a TR NOX Annual source are in excess 

of the TR NOX Annual 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 Annual 

unit at the source shall hold the TR NOX Annual allowances required 

for deduction under §97.424(d); and

(B) The owners and operators of the source and each TR NOX Annual unit 

at the source shall pay any fine, penalty, or assessment or comply 
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with any other remedy imposed, for the same violations, under the 

Clean Air Act, and 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 total NOX emissions 

during a control period in a given year from all TR NOX Annual units 

at TR NOX Annual sources in a State (and Indian country within the 

borders of such State) exceed the State assurance level, then the 

owners and operators of such sources and units in each group of one 

or more sources and units having a common designated representative 

for such control period, where the common designated representative’s

share of such NOX emissions during such control period exceeds the 

common designated representative’s assurance level for the State and 

such control period, shall hold (in the assurance account established 

for the owners and operators of such group) TR NOX Annual allowances 

available for deduction for such control period under §97.425(a) in 

an amount equal to two times the product (rounded to the nearest 

whole number), as determined by the Administrator in accordance with 

§97.425(b), of multiplying—

(A) The quotient of the amount by which the common designated 

representative’s share of such NOX emissions exceeds the common 

designated representative’s assurance level divided by the sum of the 

amounts, determined for all common designated representatives for 

such sources and units in the State (and Indian country within the 
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borders of such State) for such control period, by which each common 

designated representative’s share of such NOX emissions exceeds the 

respective common designated representative’s assurance level; and

(B) The amount by which total NOX emissions from all TR NOX Annual 

units at TR NOX Annual sources in the State (and Indian country within 

the borders of such State) for such control period exceed the State 

assurance level. 

(ii) The owners and operators 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) Total NOX emissions from all TR NOX Annual units at TR NOX

Annual sources in a State (and Indian country within the borders of 

such State) during a control period in a given year exceed the State 

assurance level if such total NOX emissions exceed the sum, for such 

control period, of the State NOX Annual trading budget under 

§97.410(a) and the State’s variability limit under §97.410(b).

(iv) It shall not be a violation of this subpart or of the Clean Air 

Act if total NOX emissions from all TR NOX Annual units at TR NOX

Annual sources in a State (and Indian country within the borders of 

such State) during a control period exceed the State assurance level 
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or if a common designated representative’s share of total NOX

emissions from the TR NOX Annual units at TR NOX Annual sources in a 

State (and Indian country within the borders of such State) during a 

control period exceeds the common designated representative’s

assurance level. 

(v) To the extent the owners and operators fail to hold TR NOX Annual 

allowances for a control period in a given year in accordance with 

paragraphs (c)(2)(i) through (iii) of this section, 

(A) The owners and operators 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 owners and operators fail to 

hold for such control period in accordance with paragraphs (c)(2)(i) 

through (iii) 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 under paragraphs (c)(1) and (c)(2) 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.
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(4) Vintage of allowances held for compliance. (i) A TR NOX Annual 

allowance held for compliance with the requirements under paragraph 

(c)(1)(i) of this section for a control period in a given year must 

be a TR NOX Annual allowance that was allocated for such control 

period or a control period in a prior year.

(ii) A TR NOX Annual allowance held for compliance with the 

requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through (iii)

of this section for a control period in a given year must be a TR NOX

Annual allowance that was allocated for a control period in a prior 

year or the control period in the given year or in the immediately 

following year.

(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. A TR NOX Annual allowance is a limited 

authorization to emit one ton of NOX during the control period in one 

year. Such authorization is limited in its use and duration as 

follows:

(i) Such authorization shall only be used in accordance with the TR 

NOX Annual Trading Program; and
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(ii) Notwithstanding any other provision of this subpart, the 

Administrator has the authority to terminate or limit the use and 

duration of 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 
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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 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 certificate of representation 

and 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.
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(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.

(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, except as provided in §97.418. 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 
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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, is not a business day, 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, 

Indian country new unit set-aside, and variability limits.
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(a) The State NOX Annual trading budgets, new unit set-asides, and 

Indian country 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)*

for 2012 and 2013

New unit setaside (tons)

for 2012 and 

2013

Indian country new 

unit set-aside 

(tons)

for 2012 and 2013

Alabama 72,691 1,454 ---

Georgia 62,010 1,240 ---

Illinois 47,872 3,830 ---

Indiana 109,726 3,292 ---

Iowa 38,335 729 38

Kansas 30,714 583 31

Kentucky 85,086 3,403 ---

Maryland 16,633 333 ---

Michigan 60,193 1,144 60

Minnesota 29,572 561 30

Missouri 52,374 1,571 ---

Nebraska 26,440 1,825 26

New Jersey 7,266 145 ---

New York 17,543 508 18

North Carolina 50,587 2,984 51

Ohio 92,703 1,854 ---

Pennsylvania 119,986 2,400 ---

South Carolina 32,498 617 33

Tennessee 35,703 714 ---

Texas 133,595 3,874 134

Virginia 33,242 1,662 ---

West Virginia 59,472 2,974 ---

Wisconsin 31,628 1,866 32

State NOX Annual trading New unit set- Indian country 
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budget (tons)*

for 2014 and 

thereafter

aside (tons)

for 2014 and 

thereafter

new unit setaside (tons)

for 2014 and 

thereafter

Alabama 71,962 1,439 ---

Georgia 40,540 811 ---

Illinois 47,872 3,830 ---

Indiana 108,424 3,253 ---

Iowa 37,498 712 38

Kansas 25,560 485 26

Kentucky 77,238 3,090 ---

Maryland 16,574 331 ---

Michigan 57,812 1,098 58

Minnesota 29,572 561 30

Missouri 48,717 1,462 ---

Nebraska 26,440 1,825 26

New Jersey 7,266 145 ---

New York 17,543 508 18

North Carolina 41,553 2,451 42

Ohio 87,493 1,750 ---

Pennsylvania 119,194 2,384 ---

South Carolina 32,498 617 33

Tennessee 19,337 387 ---

Texas 133,595 3,874 134

Virginia 33,242 1,662 ---

West Virginia 54,582 2,729 ---

Wisconsin 30,398 1,794 30

* Each trading budget includes the new unit set-aside and, where 

applicable, the Indian country new unit set-aside and does not 

include the variability limit.

(b) The States’ variability limits for the State NOX Annual trading 

budgets for the control periods in 2012 and thereafter are as 

follows:
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State

Variability limits

for 2012 and 2013

Variability limits

for 2014 and thereafter

Alabama 13,084 12,953

Georgia 11,162 7,297

Illinois 8,617 8,617

Indiana 19,751 19,516

Iowa 6,900 6,750

Kansas 5,529 4,601

Kentucky 15,315 13,903

Maryland 2,994 2,983

Michigan 10,835 10,406

Minnesota 5,323 5,323

Missouri 9,427 8,769

Nebraska 4,759 4,759

New Jersey 1,308 1,308

New York 3,158 3,158

North Carolina 9,106 7,480

Ohio 16,687 15,749

Pennsylvania 21,597 21,455

South Carolina 5,850 5,850

Tennessee 6,427 3,481

Texas 24,047 24,047

Virginia 5,984 5,984

West Virginia 10,705 9,825

Wisconsin 5,693 5,472

§ 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 provided in

a notice of data availability issued by the Administrator. Providing 

an allocation to a unit in such notice does not constitute a 

determination that the unit is a TR NOX Annual unit, and not providing 
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an allocation to a unit in such notice 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 

provided an allocation in the notice of data availability issued 

under paragraph (a)(1) of this section does not operate, starting 

after 2011, during the control period in two consecutive years, such 

unit will not be allocated the TR NOX Annual allowances provided in 

such notice for the unit for the control periods in the fifth year 

after the first such year and in each year after that fifth 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 

State where such unit is located and 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) New unit set-asides. (i) By June 1, 2012 and 

June 1 of each year thereafter, the Administrator will calculate the 

TR NOX Annual allowance allocation to each TR NOX Annual unit in a 

State, in accordance with §97.412(a)(2) through (7) and (12), for the 

control period in the year of the applicable calculation deadline 

under this paragraph and will promulgate a notice of data 

availability of the results of the calculations.
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(ii) For each notice of data availability required in paragraph 

(b)(1)(i) of this section, the Administrator will provide an 

opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR NOX Annual units) are in 

accordance with §97.412(a)(2) through (7) and (12) and §§97.406(b)(2) 

and 97.430 through 97.435. 

(B) The Administrator will adjust the calculations to the extent 

necessary to ensure that they are in accordance with the provisions 

referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(1)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.412(a)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) of this section. 

(iii) If the new unit set-aside for such control period contains any 

TR NOX Annual allowances that have not been allocated in the 

applicable notice of data availability required in paragraph 
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(b)(1)(ii) of this section, the Administrator will promulgate, by 

December 15 immediately after such notice, a notice of data 

availability that identifies any TR NOX Annual units that commenced 

commercial operation during the period starting January 1 of the year 

before the year of such control period and ending November 30 of year 

of such control period.

(iv) For each notice of data availability required in paragraph 

(b)(1)(iii) of this section, the Administrator will provide an 

opportunity for submission of objections to the identification of TR 

NOX annual units in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR NOX annual units in such notice is in accordance with paragraph 

(b)(1)(iii) of this section. 

(B) The Administrator will adjust the identification of TR NOX Annual 

units in the each notice of data availability required in paragraph 

(b)(1)(iii) of this section to the extent necessary to ensure that it 

is in accordance with paragraph (b)(1)(iii) of this section and will 

calculate the TR NOX Annual allowance allocation to each TR NOX Annual 

unit in accordance with §97.412(a)(9), (10), and (12) and 

§§97.406(b)(2) and 97.430 through 97.435. By February 15 immediately 

after the promulgation of each notice of data availability required 
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in paragraph (b)(1)(iii) of this section, the Administrator will 

promulgate a notice of data availability of any adjustments of the 

identification of TR NOX Annual units that the Administrator 

determines to be necessary, the reasons for accepting or rejecting 

any objections submitted in accordance with paragraph (b)(1)(iv)(A)

of this section, and the results of such calculations.

(v) To the extent any TR NOX Annual allowances are added to the new 

unit set-aside after promulgation of each notice of data availability 

required in paragraph (b)(1)(iv) of this section, the Administrator 

will promulgate additional notices of data availability, as deemed 

appropriate, of the allocation of such TR NOX Annual allowances in 

accordance with §97.412(a)(10). 

(2) Indian country new unit set-asides. (i) By June 1, 2012 and June

1 of each year thereafter, the Administrator will calculate the TR NOX

Annual allowance allocation to each TR NOX Annual unit in Indian 

country within the borders of a State, in accordance with 

§97.412(b)(2) through (7) and (12), for the control period in the 

year of the applicable calculation deadline under this paragraph and 

will promulgate a notice of data availability of the results of the 

calculations.

(ii) For each notice of data availability required in paragraph 

(b)(2)(i) of this section, the Administrator will provide an 
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opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR NOX Annual units) are in 

accordance with §97.412(b)(2) through (7) and (12) and §§97.406(b)(2) 

and 97.430 through 97.435. 

(B) 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)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.412(b)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) of this section. 

(iii) If the Indian country new unit set-aside for such control 

period contains any TR NOX Annual allowances that have not been 

allocated in the applicable notice of data availability required in 

paragraph (b)(2)(ii) of this section, the Administrator will 

promulgate, by December 15 immediately after such notice, a notice of 
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data availability that identifies any TR NOX Annual units that 

commenced commercial operation during the period starting January 1 

of the year before the year of such control period and ending 

November 30 of year of such control period.

(iv) For each notice of data availability required in paragraph

(b)(2)(iii) of this section, the Administrator will provide an 

opportunity for submission of objections to the identification of TR 

NOX annual units in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR NOX annual units in such notice is in accordance with paragraph 

(b)(2)(iii) of this section. 

(B) The Administrator will adjust the identification of TR NOX Annual 

units in the each notice of data availability required in paragraph 

(b)(2)(iii) of this section to the extent necessary to ensure that it 

is in accordance with paragraph (b)(2)(iii) of this section and will 

calculate the TR NOX Annual allowance allocation to each TR NOX Annual 

unit in accordance with §97.412(b)(9), (10), and (12) and 

§§97.406(b)(2) and 97.430 through 97.435. By February 15 immediately 

after the promulgation of each notice of data availability required 

in paragraph (b)(2)(iii) of this section, the Administrator will 

promulgate a notice of data availability of any adjustments of the 
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identification of TR NOX Annual units that the Administrator 

determines to be necessary, the reasons for accepting or rejecting 

any objections submitted in accordance with paragraph (b)(2)(iv)(A)

of this section, and the results of such calculations. 

(v) To the extent any TR NOX Annual allowances are added to the Indian 

country new unit set-aside after promulgation of each notice of data 

availability required in paragraph (b)(2)(iv) of this section, the 

Administrator will promulgate additional notices of data 

availability, as deemed appropriate, of the allocation of such TR NOX

Annual allowances in accordance with §97.412(b)(10).

(c) Units incorrectly allocated TR NOX Annual allowances. (1) 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, or under a provision of a SIP revision 

approved under §52.38(a)(3), (4), or (5) of this chapter, where such 

control period and the recipient are covered by the provisions of 

paragraph (c)(1)(i) of this section or were allocated under 

§97.412(a)(2) through (7), (9), and (12) and (b)(2) through (7), (9), 

and (12), or under a provision of a SIP revision approved under 

§52.38(a)(4) or (5) of this chapter, where such control period and 

the recipient are covered by the provisions of paragraph (c)(1)(ii) 

of this section, then the Administrator will notify the designated 

representative of the recipient and will act in accordance with the 
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procedures set forth in paragraphs (c)(2) through (5) of this 

section:

(i)(A) The recipient is not actually a TR NOX Annual unit under 

§97.404 as of January 1, 2012 and is allocated TR NOX Annual 

allowances for such control period or, in the case of an allocation 

under a provision of a SIP revision approved under §52.38(a)(3), (4), 

or (5) of this chapter, the recipient is not actually a TR NOX Annual 

unit as of January 1, 2012 and is allocated TR NOX Annual allowances 

for such control period that the SIP revision provides should be 

allocated only to recipients that are TR NOX Annual units as of 

January 1, 2012; or

(B) The recipient is not located as of January 1 of the control 

period in the State from whose NOX Annual trading budget the TR NOX

Annual allowances allocated under paragraph (a) of this section, or 

under a provision of a SIP revision approved under §52.38(a)(3), (4), 

or (5) of this chapter, were allocated for such control period. 

(ii) The recipient is not actually a TR NOX Annual unit under §97.404 

as of January 1 of such control period and is allocated TR NOX Annual 

allowances for such control period or, in the case of an allocation 

under a provision of a SIP revision approved under §52.38(a)(3), (4), 

or (5) of this chapter, the recipient is not actually a TR NOX Annual 

unit as of January 1 of such control period and is allocated TR NOX

Annual allowances for such control period that the SIP revision 
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provides should be allocated only to recipients that are TR NOX Annual 

units as of January 1 of such control period. 

(2) Except as provided in paragraph (c)(3) or (4) of this section, 

the Administrator will not record such TR NOX Annual allowances under 

§97.421.

(3) If the Administrator already recorded such TR NOX Annual 

allowances under §97.421 and if the Administrator makes the

determination under paragraph (c)(1) of this section 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.

(4) If the Administrator already recorded such TR NOX Annual 

allowances under §97.421 and if the Administrator makes the

determination under paragraph (c)(1) of this section 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. 
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(5)(i) With regard to the TR NOX Annual allowances that are not 

recorded, or that are deducted as an incorrect allocation, in 

accordance with paragraphs (c)(2) and (3) of this section for a 

recipient under paragraph (c)(1)(i) of this section, the 

Administrator will:

(A) Transfer such TR NOX Annual allowances to the new unit set-aside 

for such control period for the State from whose NOX Annual trading 

budget the TR NOX Annual allowances were allocated; or

(B) If the State has a SIP revision approved under §52.38(a)(4) or 

(5) covering such control period, include such TR NOX Annual 

allowances in the portion of the State NOX Annual trading budget that 

may be allocated for such control period in accordance with such SIP 

revision. 

(ii) With regard to the TR NOX Annual allowances that were not

allocated from the Indian country new unit set-aside for such control 

period and that are not recorded, or that are deducted as an 

incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 

this section for a recipient under paragraph (c)(1)(ii) of this 

paragraph, the Administrator will:

(A) Transfer such TR NOX Annual allowances to the new unit set-aside 

for such control period; or
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(B) If the State has a SIP revision approved under §52.38(a)(4) or 

(5) covering such control period, include such TR NOX Annual 

allowances in the portion of the State NOX Annual trading budget that 

may be allocated for such control period in accordance with such SIP 

revision. 

(iii) With regard to the TR NOX Annual allowances that were allocated 

from the Indian country new unit set-aside for such control period 

and that are not recorded, or that are deducted as an incorrect 

allocation, in accordance with paragraphs (c)(2) and (3) of this 

section for a recipient under paragraph (c)(1)(ii) of this paragraph, 

the Administrator will transfer such TR NOX Annual allowances to the 

Indian country new unit set-aside for such control period.

§ 97.412 TR NOX Annual allowance allocations to new units.

(a) For each control period in 2012 and thereafter and for the TR NOX

Annual units in each State, the Administrator will allocate TR NOX

Annual allowances to the TR NOX Annual units as follows: 

(1) The TR NOX Annual allowances will be allocated to the following TR 

NOX Annual units, except as provided in paragraph (a)(10) of this 

section:

(i) TR NOX Annual units that are not allocated an amount of TR NOX

Annual allowances in the notice of data availability issued under 

§97.411(a)(1);
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(ii) TR NOX Annual units whose allocation of an amount of TR NOX

Annual allowances for such control period in the notice of data 

availability issued under §97.411(a)(1) is covered by §97.411(c)(2) 

or (3);

(iii) TR NOX Annual units that are allocated an amount of TR NOX

Annual allowances for such control period in the notice of data 

availability issued under §97.411(a)(1), which allocation is 

terminated for such control period pursuant to §97.411(a)(2), and 

that operate during the control period immediately preceding such 

control period; or

(iv) For purposes of paragraph (a)(9) of this section, TR NOX Annual 

units under §97.411(c)(1)(ii) whose allocation of an amount of TR NOX

Annual allowances for such control period in the notice of data 

availability issued under §97.411(b)(1)(ii)(B) is covered by 

§97.411(c)(2) or (3). 

(2) The Administrator will establish a separate new unit set-aside 

for the State for each such control period. Each such new unit setaside 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) and will be allocated additional TR NOX Annual allowances 

(if any) in accordance with §§97.411(a)(2) and (c)(5) and paragraph 

(b)(10) of this section.
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(3) The Administrator will determine, for each TR NOX Annual unit

described in paragraph (a)(1) of this section, an allocation of TR NOX

Annual allowances for the later of the following control periods and 

for each subsequent control period:

(i) The control period in 2012;

(ii) The first control period after the control period in which the 

TR NOX Annual unit commences commercial operation;

(iii) For a unit described in paragraph (a)(1)(ii) of this section, 

the first control period in which the TR NOX Annual unit operates in 

the State after operating in another jurisdiction and for which the 

unit is not already allocated one or more TR NOX Annual allowances; 

and

(iv) For a unit described in paragraph (a)(1)(iii) of this section, 

the first control period after the control period in which the unit 

resumes operation. 

(4)(i) The allocation to each TR NOX annual unit described in 

paragraph (a)(1)(i) through (iii) of this section and for each 

control period described in paragraph (a)(3) of this section will be 

an amount equal to the unit’s total tons of NOX emissions during the 

immediately preceding control period.
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(ii) The Administrator will adjust the allocation amount in paragraph 

(a)(4)(i) in accordance with paragraphs (a)(5) through (7) and (12)

of this section.

(5) The Administrator will calculate the sum of the TR NOX Annual 

allowances determined for all such TR NOX Annual units under paragraph 

(a)(4)(i) of this section in the State for such control period.

(6) If the amount of TR NOX Annual allowances in the new unit setaside for the State for such control period is greater than or equal 

to the sum under paragraph (a)(5) of this section, then the 

Administrator will allocate the amount of TR NOX Annual allowances 

determined for each such TR NOX Annual unit under paragraph (a)(4)(i) 

of this section.

(7) If the amount of TR NOX Annual allowances in the new unit setaside for the State for such control period is less than the sum 

under paragraph (a)(5) of this section, then the Administrator will 

allocate to each such TR NOX Annual unit the amount of the TR NOX

Annual allowances determined under paragraph (a)(4)(i) of this 

section for the unit, multiplied by the amount of TR NOX Annual 

allowances in the new unit set-aside for such control period, divided 

by the sum under paragraph (a)(5) of this section, and rounded to the 

nearest allowance.
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(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.411(b)(1)(i) and (ii), of the amount of TR NOX Annual allowances

allocated under paragraphs (a)(2) through (7) and (12) of this 

section for such control period to each TR NOX Annual unit eligible 

for such allocation.

(9) If, after completion of the procedures under paragraphs (a)(5) 

through (8) of this section for such control period, any unallocated 

TR NOX Annual allowances remain in the new unit set-aside for the

State for such control period, the Administrator will allocate such 

TR NOX Annual allowances as follows--

(i) The Administrator will determine, for each unit described in 

paragraph (a)(1) of this section that commenced commercial operation 

during the period starting January 1 of the year before the year of 

such control period and ending November 30 of year of such control 

period, the positive difference (if any) between the unit’s emissions 

during such control period and the amount of TR NOX Annual allowances 

referenced in the notice of data availability required under 

§97.411(b)(1)(ii) for the unit for such control period;

(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (a)(9)(i) of this section;
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(iii) If the amount of unallocated TR NOX Annual allowances remaining 

in the new unit set-aside for the State for such control period is 

greater than or equal to the sum determined under paragraph 

(a)(9)(ii) of this section, then the Administrator will allocate the 

amount of TR NOX Annual allowances determined for each such TR NOX

Annual unit under paragraph (a)(9)(i) of this section; and

(iv) If the amount of unallocated TR NOX Annual allowances remaining 

in the new unit set-aside for the State for such control period is 

less than the sum under paragraph (a)(9)(ii) of this section, then 

the Administrator will allocate to each such TR NOX Annual unit the 

amount of the TR NOX Annual allowances determined under paragraph 

(a)(9)(i) of this section for the unit, multiplied by the amount of 

unallocated TR NOX Annual allowances remaining in the new unit setaside for such control period, divided by the sum under paragraph 

(a)(9)(ii) of this section, and rounded to the nearest allowance.

(10) If, after completion of the procedures under paragraphs (a)(9)

and (12) of this section for such control period, any unallocated TR 

NOX Annual allowances remain in the new unit set-aside for the State 

for such control period, the Administrator will allocate to each TR 

NOX Annual unit that is in the State, is allocated an amount of TR NOX

Annual allowances in the notice of data availability issued under 

§97.411(a)(1), 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 
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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 sum 

of the amounts of tons in such new unit set-aside and the Indian 

country new unit set-aside for the State for such control period, and 

rounded to the nearest allowance.

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.411(b)(1)(iii), (iv), and (v), of the amount of TR NOX Annual 

allowances allocated under paragraphs (a)(9), (10), and (12) of this 

section for such control period to each TR NOX Annual unit eligible 

for such allocation.

(12)(i) Notwithstanding the requirements of paragraphs (a)(2) through 

(11) of this section, if the calculations of allocations of a new 

unit set-aside for a control period in a given year under paragraph 

(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this 

section, or paragraphs (a)(6), (9)(iii), and (10) of this section 

would otherwise result in total allocations of such new unit setaside exceeding the total amount of such new unit set-aside, then the 

Administrator will adjust the results of the calculations under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 

follows. The Administrator will list the TR NOX Annual units in 

descending order based on the amount of such units’ allocations under 
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Page 810 of 1293

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, 

and, in cases of equal allocation amounts, in alphabetical order of 

the relevant source’s name and numerical order of the relevant unit’s 

identification number, and will reduce each unit’s allocation under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, by 

one TR NOX Annual allowance (but not below zero) in the order in which 

the units are listed and will repeat this reduction process as 

necessary, until the total allocations of such new unit set-aside 

equal the total amount of such new unit set-aside. 

(ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 

of this section, if the calculations of allocations of a new unit 

set-aside for a control period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section would otherwise result in 

a total allocations of such new unit set-aside less than the total 

amount of such new unit set-aside, then the Administrator will adjust 

the results of the calculations under paragraph (a)(10) of this 

section, as follows. The Administrator will list the TR NOX Annual 

units in descending order based on the amount of such units’ 

allocations under paragraph (a)(10) of this section and, in cases of 

equal allocation amounts, in alphabetical order of the relevant 

source’s name and numerical order of the relevant unit’s 

identification number, and will increase each unit’s allocation under 

paragraph (a)(10) of this section by one TR NOX Annual allowance in 

the order in which the units are listed and will repeat this increase 
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process as necessary, until the total allocations of such new unit 

set-aside equal the total amount of such new unit set-aside. 

(b) For each control period in 2012 and thereafter and for the TR NOX

Annual units located in Indian country within the borders of each 

State, the Administrator will allocate TR NOX Annual allowances to the 

TR NOX Annual units as follows: 

(1) The TR NOX Annual allowances will be allocated to the following TR 

NOX Annual units, except as provided in paragraph (b)(10) of this 

section:

(i) TR NOX Annual units that are not allocated an amount of TR NOX

Annual allowances in the notice of data availability issued under 

§97.411(a)(1); or

(ii) For purposes of paragraph (b)(9) of this section, TR NOX Annual 

units under §97.411(c)(1)(ii) whose allocation of an amount of TR NOX

Annual allowances for such control period in the notice of data 

availability issued under §97.411(b)(2)(ii)(B) is covered by 

§97.411(c)(2) or (3). 

(2) The Administrator will establish a separate Indian country new 

unit set-aside for the State for each such control period. Each such 

Indian country new unit set-aside will be allocated TR NOX Annual 

allowances in an amount equal to the applicable amount of tons of NOX
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Page 812 of 1293

emissions as set forth in §97.410(a) and will be allocated additional 

TR NOX Annual allowances (if any) in accordance with §97.411(c)(5).

(3) The Administrator will determine, for each TR NOX Annual unit

described in paragraph (b)(1) of this section, an allocation of TR NOX

Annual allowances for the later of the following control periods and 

for each subsequent control period:

(i) The control period in 2012; and

(ii) The first control period after the control period in which the 

TR NOX Annual unit commences commercial operation.

(4)(i) The allocation to each TR NOX annual unit described in 

paragraph (b)(1)(i) of this section and for each control period 

described in paragraph (b)(3) of this section will be an amount equal 

to the unit’s total tons of NOX emissions during the immediately 

preceding control period.

(ii) The Administrator will adjust the allocation amount in paragraph 

(b)(4)(i) in accordance with paragraphs (b)(5) through (7) and (12)

of this section.

(5) The Administrator will calculate the sum of the TR NOX Annual 

allowances determined for all such TR NOX Annual units under paragraph 

(b)(4)(i) of this section in Indian country within the borders of the 

State for such control period.
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(6) If the amount of TR NOX Annual allowances in the Indian country 

new unit set-aside for the State for such control period is greater 

than or equal to the sum under paragraph (b)(5) of this section, then 

the Administrator will allocate the amount of TR NOX Annual allowances 

determined for each such TR NOX Annual unit under paragraph (b)(4)(i) 

of this section.

(7) If the amount of TR NOX Annual allowances in the Indian country 

new unit set-aside for the State for such control period is less than 

the sum under paragraph (b)(5) of this section, then the 

Administrator will allocate to each such TR NOX Annual unit the amount 

of the TR NOX Annual allowances determined under paragraph (b)(4)(i) 

of this section for the unit, multiplied by the amount of TR NOX

Annual allowances in the Indian country new unit set-aside for such 

control period, divided by the sum under paragraph (b)(5) of this 

section, and rounded to the nearest allowance.

(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.411(b)(2)(i) and (ii), of the amount of TR NOX Annual allowances 

allocated under paragraphs (b)(2) through (7) and (12) of this 

section for such control period to each TR NOX Annual unit eligible 

for such allocation.

(9) If, after completion of the procedures under paragraphs (b)(5) 

through (8) of this section for such control period, any unallocated 
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TR NOX Annual allowances remain in the Indian country new unit setaside for the State for such control period, the Administrator will 

allocate such TR NOX Annual allowances as follows--

(i) The Administrator will determine, for each unit described in 

paragraph (b)(1) of this section that commenced commercial operation 

during the period starting January 1 of the year before the year of 

such control period and ending November 30 of year of such control 

period, the positive difference (if any) between the unit’s emissions 

during such control period and the amount of TR NOX Annual allowances 

referenced in the notice of data availability required under 

§97.411(b)(2)(ii) for the unit for such control period;

(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (b)(9)(i) of this section;

(iii) If the amount of unallocated TR NOX Annual allowances remaining 

in the Indian country new unit set-aside for the State for such 

control period is greater than or equal to the sum determined under

paragraph (b)(9)(ii) of this section, then the Administrator will

allocate the amount of TR NOX Annual allowances determined for each 

such TR NOX Annual unit under paragraph (b)(9)(i) of this section; and

(iv) If the amount of unallocated TR NOX Annual allowances remaining 

in the Indian country new unit set-aside for the State for such 

control period is less than the sum under paragraph (b)(9)(ii) of 
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Page 815 of 1293

this section, then the Administrator will allocate to each such TR NOX

Annual unit the amount of the TR NOX Annual allowances determined 

under paragraph (b)(9)(i) of this section for the unit, multiplied by 

the amount of unallocated TR NOX Annual allowances remaining in the 

Indian country new unit set-aside for such control period, divided by 

the sum under paragraph (b)(9)(ii) of this section, and rounded to 

the nearest allowance.

(10) If, after completion of the procedures under paragraphs (b)(9) 

and (12) of this section for such control period, any unallocated TR 

NOX Annual allowances remain in the Indian country new unit set-aside 

for the State for such control period, the Administrator will:

(i) Transfer such unallocated TR NOX Annual allowances to the new unit 

set-aside for the State for such control period; or 

(ii) If the State has a SIP revision approved under §52.38(a)(4) or 

(5) covering such control period, include such unallocated TR NOX

Annual allowances in the portion of the State NOX Annual trading 

budget that may be allocated for such control period in accordance 

with such SIP revision. 

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.411(b)(2)(iii), (iv), and (v), of the amount of TR NOX Annual 

allowances allocated under paragraphs (b)(9), (10), and (12) of this 
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section for such control period to each TR NOX Annual unit eligible 

for such allocation.

(12)(i) Notwithstanding the requirements of paragraphs (b)(2) through 

(11) of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 

paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) of 

this section, or paragraphs (b)(6), (9)(iii), and (10) of this 

section would otherwise result in total allocations of such Indian 

country new unit set-aside exceeding the total amount of such Indian 

country new unit set-aside, then the Administrator will adjust the 

results of the calculations under paragraph (b)(7), (9)(iv), or (10) 

of this section, as applicable, as follows. The Administrator will 

list the TR NOX Annual units in descending order based on the amount 

of such units’ allocations under paragraph (b)(7), (9)(iv), or (10) 

of this section, as applicable, and, in cases of equal allocation 

amounts, in alphabetical order of the relevant source’s name and 

numerical order of the relevant unit’s identification number, and 

will reduce each unit’s allocation under paragraph (b)(7), (9)(iv), 

or (10) of this section, as applicable, by one TR NOX Annual allowance 

(but not below zero) in the order in which the units are listed and 

will repeat this reduction process as necessary, until the total 

allocations of such Indian country new unit set-aside equal the total 

amount of such Indian country new unit set-aside. 
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(ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 

of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 

paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 

result in a total allocations of such Indian country new unit setaside less than the total amount of such Indian country new unit setaside, then the Administrator will adjust the results of the 

calculations under paragraph (b)(10) of this section, as follows. 

The Administrator will list the TR NOX Annual units in descending 

order based on the amount of such units’ allocations under paragraph 

(b)(10) of this section and, in cases of equal allocation amounts, in 

alphabetical order of the relevant source’s name and numerical order 

of the relevant unit’s identification number, and will increase each 

unit’s allocation under paragraph (b)(10) of this section by one TR 

NOX Annual allowance in the order in which the units are listed and 

will repeat this increase process as necessary, until the total 

allocations of such Indian country new unit set-aside equal the total 

amount of such Indian country new unit set-aside. 

§ 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.
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(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.
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(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” (as distinguished from 

the term “common designated representative”) is used in this subpart, 

the term shall be construed to include the designated representative 

or any alternate designated representative.
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§ 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 
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Page 821 of 1293

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; changes in units at 

the source.

(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 
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Page 822 of 1293

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 at the 

source 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 at the source, including 

the addition or removal of an 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 reflect the change.

(d) Changes in units at the source. Within 30 days of any change in 

which units are located at a TR NOX Annual source (including the 

addition or removal of a unit), the designated representative or any 

alternate designated representative shall submit a certificate of 
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representation under §97.416 amending the list of units to reflect 

the change. 

(1) If the change is the addition of a unit that operated (other than 

for purposes of testing by the manufacturer before initial 

installation) before being located at the source, then the 

certificate of representation shall identify, in a format prescribed 

by the Administrator, the entity from whom the unit was purchased or 

otherwise obtained (including name, address, telephone number, and 

facsimile number (if any)), the date on which the unit was purchased 

or otherwise obtained, and the date on which the unit became located 

at the source.

(2) If the change is the removal of a unit, then the certificate of 

representation shall identify, in a format prescribed by the 

Administrator, the entity to which the unit was sold or that 

otherwise obtained the unit (including name, address, telephone 

number, and facsimile number (if any)), the date on which the unit 

was sold or otherwise obtained, and the date on which the unit became 

no longer located at the source. 

§ 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:
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(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, actual or projected date of commencement of commercial 

operation, and a statement of whether such source is located in 

Indian Country. If a projected date of commencement of commercial 

operation is provided, the actual date of commencement of commercial 

operation shall be provided when such information becomes available.

(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 
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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 decision or 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-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 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 
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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.

§ 97.417 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 paragraph (a) of this section, 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 
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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 a natural person 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:
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(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 in this section 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 
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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 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 compliance accounts, assurance accounts, 

and general accounts.

(a) Compliance accounts. Upon receipt of a complete certificate of 

representation under §97.416, the Administrator will establish a 
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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) Assurance accounts. The Administrator will establish assurance

accounts for certain owners and operators and States in accordance 

with §97.425(b)(3). 

(c) 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. 
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(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
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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 decision or order 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 
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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 

decision or order issued to the authorized account representative or 

alternate authorized account representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph (c)(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 
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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 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 (c)(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 
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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 (c)(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.
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(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 or removal of a 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 (c)(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 (c)(4)(i) 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.
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(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 a natural person to make an 

electronic submission to the Administrator in accordance with 

paragraph (c)(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:
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(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 in this section as an “agent”);

(C) For each such natural person, a list of the type or types of 

electronic submissions under paragraph (c)(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(c)(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 
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delegation under 40 CFR 97.420(c)(5)(iv), I agree to maintain an email 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(c)(5) is terminated.”.

(iv) A notice of delegation submitted under paragraph (c)(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 (c)(5)(iii)(D) of this section and made in accordance with 

a notice of delegation effective under paragraph (c)(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) Closing a general account. (i) The authorized account 

representative or alternate authorized account representative of a 

general account may submit to the Administrator a request to close 
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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 30 days after the notice is sent. The account 

will be closed after the 30-day period unless, before the end of the 

30-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.

(d) Account identification. The Administrator will assign a unique 

identifying number to each account established under paragraph (a),

(b), or (c) of this section.

(e) Responsibilities of authorized account representative and 

alternate authorized account representative. After the establishment 

of a compliance account or general account, the Administrator will 

accept or act on a submission pertaining to the account, including, 
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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 (c)(2)(ii) and (c)(5) of this section. 

§ 97.421 Recordation of TR NOX Annual allowance allocations and 

auction results.

(a) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR NOX Annual 

source's compliance account the TR NOX Annual allowances allocated to

the TR NOX Annual units at the source in accordance with §97.411(a) 

for the control period in 2012.

(b) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR NOX Annual 

source's compliance account the TR NOX Annual allowances allocated to

the TR NOX Annual units at the source in accordance with §97.411(a)

for the control period in 2013, unless the State in which the source 

is located notifies the Administrator in writing by [INSERT DATE 70 

DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER] of the State’s 

intent to submit to the Administrator a complete SIP revision by 

April 1, 2012 meeting the requirements of §52.38(a)(3)(i) through 

(iv) of this chapter.
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(1) If, by April 1, 2012, the State does not submit to the 

Administrator such complete SIP revision, the Administrator will 

record by April 15, 2012 in each TR NOX Annual source's compliance 

account the TR NOX Annual allowances allocated to the TR NOX Annual 

units at the source in accordance with §97.411(a) for the control 

period in 2013.

(2) If the State submits to the Administrator by April 1, 2012, and 

the Administrator approves by October 1, 2012, such complete SIP 

revision, the Administrator will record by October 1, 2012 in each TR 

NOX Annual source's compliance account the TR NOX Annual allowances 

allocated to the TR NOX Annual units at the source as provided in such 

approved, complete SIP revision for the control period in 2013.

(3) If the State submits to the Administrator by April 1, 2012, and 

the Administrator does not approve by October 1, 2012, such complete 

SIP revision, the Administrator will record by October 1, 2012 in 

each TR NOX Annual source's compliance account the TR NOX Annual 

allowances allocated to the TR NOX Annual units at the source in 

accordance with §97.411(a) for the control period in 2013.

(c) By July 1, 2013, the Administrator will record in each TR NOX

Annual source's compliance account the TR NOX Annual allowances 

allocated to the TR NOX Annual units at the source, or in each 

appropriate Allowance Management System account the TR NOX Annual 

allowances auctioned to TR NOX Annual units, in accordance with 
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§97.411(a), or with a SIP revision approved under §52.38(a)(4) or (5) 

of this chapter, for the control period in 2014 and 2015.

(d) By July 1, 2014, the Administrator will record in each TR NOX

Annual source's compliance account the TR NOX Annual allowances 

allocated to the TR NOX Annual units at the source, or in each 

appropriate Allowance Management System account the TR NOX Annual 

allowances auctioned to TR NOX Annual units, in accordance with 

§97.411(a), or with a SIP revision approved under §52.38(a)(4) or (5) 

of this chapter, for the control period in 2016 and 2017.

(e) By July 1, 2015, the Administrator will record in each TR NOX

Annual source's compliance account the TR NOX Annual allowances 

allocated to the TR NOX Annual units at the source, or in each 

appropriate Allowance Management System account the TR NOX Annual 

allowances auctioned to TR NOX Annual units, in accordance with 

§97.411(a), or with a SIP revision approved under §52.38(a)(4) or (5) 

of this chapter, for the control period in 2018 and 2019.

(f) By July 1, 2016 and July 1 of each year thereafter, the 

Administrator will record in each TR NOX Annual source's compliance 

account the TR NOX Annual allowances allocated to the TR NOX Annual 

units at the source, or in each appropriate Allowance Management 

System account the TR NOX Annual allowances auctioned to TR NOX Annual 

units, in accordance with §97.411(a), or with a SIP revision approved 

under §52.38(a)(4) or (5) of this chapter, for the control period in 
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the fourth year after the year of the applicable recordation deadline 

under this paragraph.

(g) By August 1, 2012 and August 1 of each year thereafter, the 

Administrator will record in each TR NOX Annual source's compliance 

account the TR NOX Annual allowances allocated to the TR NOX Annual 

units at the source, or in each appropriate Allowance Management 

System account the TR NOX Annual allowances auctioned to TR NOX Annual 

units, in accordance with §97.412(a)(2) through (8) and (12), or with 

a SIP revision approved under §52.38(a)(4) or (5) of this chapter,

for the control period in the year of the applicable recordation 

deadline under this paragraph.

(h) By August 1, 2012 and August 1 of each year thereafter, the 

Administrator will record in each TR NOX Annual source's compliance 

account the TR NOX Annual allowances allocated to the TR NOX Annual 

units at the source in accordance with §97.412(b)(2) through (8) and 

(12) for the control period in the year of the applicable recordation 

deadline under this paragraph.

(i) By February 15, 2013 and February 15 of each year thereafter, the 

Administrator will record in each TR NOX Annual source's compliance 

account the TR NOX Annual allowances allocated to the TR NOX Annual 

units at the source in accordance with §97.412(a)(9) through (12),

for the control period in the year before the year of the applicable 

recordation deadline under this paragraph.
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(j) By the date on which any allocation or auction results, other 

than an allocation or auction results described in paragraphs (a) 

through (i) of this section, of TR NOX Annual allowances to a 

recipient is made by or are submitted to the Administrator in 

accordance with §97.411 or §97.412 or with a SIP revision approved 

under §52.38(a)(4) or (5) of this chapter, the Administrator will 

record such allocation or auction results in the appropriate 

Allowance Management System account. 

(k) When recording the allocation or auction of TR NOX Annual 

allowances to a TR NOX Annual unit or other entity in an Allowance 

Management System 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 or auctioned.

§ 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:
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(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 that is 

correctly submitted under §97.422, 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 in 

the transfer. 

(b) A TR NOX Annual allowance transfer to or from a compliance account 

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 
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completes the deductions from such compliance account under §97.424 

for the control period immediately before such allowance transfer 

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 non-recordation.

§ 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:
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(1) Were allocated for such control period or a control period in 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 in a given year, the 

Administrator will deduct from each source’s compliance account TR NOX

Annual allowances available under paragraph (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 
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or excess emissions for a control period in a given year 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 

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 
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Administrator will deduct from the source's compliance account an 

amount of TR NOX Annual allowances, allocated for a control period in 

a prior year or the control period in the year of the excess 

emissions or 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 the 

owners and operators of a group of one or more TR NOX Annual sources 

and units in a State (and Indian country within the borders of such 

State) only if the TR NOX Annual allowances: 

(1) Were allocated for a control period in a prior year or the 

control period in the given year or in the immediately following 

year; and

(2) Are held in the assurance account, established by the 

Administrator for such owners and operators of such group of TR NOX

Annual sources and units in such State (and Indian country within 
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the borders of such State) under paragraph (b)(3) of this section, as 

of the deadline established in paragraph (b)(4) 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, 2013 and June 1 of each year thereafter, the 

Administrator will:

(i) Calculate, for each State (and Indian country within the borders 

of such State), the total NOX emissions from all TR NOX Annual units 

at TR NOX Annual sources in the State (and Indian country within the 

borders of such State) during the control period in the year before 

the year of this calculation deadline and the amount, if any, by 

which such total NOX emissions exceed the State assurance level as 

described in §97.406(c)(2)(iii); and

(ii) Promulgate a notice of data availability of the results of the 

calculations required in paragraph (b)(1)(i) of this section, 

including separate calculations of the NOX emissions from each TR NOX

Annual source. 

(2) For each notice of data availability required in paragraph 

(b)(1)(ii) of this section and for any State (and Indian country 
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within the borders of such State) identified in such notice as having 

TR NOX Annual units with total NOX emissions exceeding the State 

assurance level for a control period in a given year, as described in 

§97.406(c)(2)(iii):

(i) By July 1 immediately after the promulgation of such notice, the 

designated representative of each TR NOX Annual source in each such 

State (and Indian country within the borders of such State) shall 

submit a statement, in a format prescribed by the Administrator, 

providing for each TR NOX Annual unit (if any) at the source that 

operates during, but is not allocated an amount of TR NOX Annual 

allowances for, such control period, the unit’s allowable NOX emission 

rate for such control period and, if such rate is expressed in lb per 

mmBtu, the unit’s heat rate. 

(ii) By August 1 immediately after the promulgation of such notice, 

the Administrator will calculate, for each such State (and Indian 

country within the borders of such State) and such control period and 

each common designated representative for such control period for a 

group of one or more TR NOX Annual sources and units in the State (and 

Indian country within the borders of such State), the common 

designated representative’s share of the total NOX emissions from all 

TR NOX Annual units at TR NOX Annual sources in the State (and Indian 

country within the borders of such State), the common designated 

representative’s assurance level, and the amount (if any) of TR NOX

Annual allowances that the owners and operators of such group of 
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sources and units must hold in accordance with the calculation 

formula in §97.406(c)(2)(i) and will promulgate a notice of data 

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)(2)(ii) of this section and the 

calculations referenced by the relevant notice of data availability 

required in paragraph (b)(1)(i) of this section.

(A) Objections shall be submitted by the deadline specified in such 

notice and shall be limited to addressing whether the calculations 

referenced in the relevant notice required under paragraph (b)(1)(ii) 

of this section and referenced in the notice required under paragraph 

(b)(2)(ii) of this section are in accordance with §97.406(c)(2)(iii),

§§97.406(b) and 97.430 through 97.435, the definitions of “common 

designated representative”, “common designated representative’s

assurance level”, and “common designated representative’s share” in 

§97.402, and the calculation formula in §97.406(c)(2)(i).

(B) 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)(iii)(A) of this section. By October 1

immediately after the promulgation of such notice, the Administrator 

will promulgate a notice of data availability of any adjustments that 

the Administrator determines to be necessary and the reasons for 
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accepting or rejecting any objections submitted in accordance with 

paragraph (b)(2)(iii)(A) of this section.

(3) For any State (and Indian country within the borders of such 

State) referenced in each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section as having TR NOX Annual units

with total NOX emissions exceeding the State assurance level for a 

control period in a given year, the Administrator will establish one 

assurance account for each set of owners and operators referenced, in 

the notice of data availability required under paragraph 

(b)(2)(iii)(B) of this section, as all of the owners and operators of 

a group of TR NOX Annual sources and units in the State (and Indian 

country within the borders of such State) having a common designated 

representative for such control period and as being required to hold 

TR NOX Annual allowances. 

(4)(i) As of midnight of November 1 immediately after the 

promulgation of each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section, the owners and operators

described in paragraph (b)(3) of this section shall hold in the 

assurance account established for the them and for the appropriate TR 

NOX Annual sources, TR NOX Annual units, and State (and Indian country 

within the borders of such State) under paragraph (b)(3) of this 

section a total amount of TR NOX Annual allowances, available for 

deduction under paragraph (a) of this section, equal to the amount 

such owners and operators are required to hold with regard to such 
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sources, units and State (and Indian country within the borders of 

such State) as calculated by the Administrator and referenced in such 

notice. 

(ii) Notwithstanding the allowance-holding deadline specified in 

paragraph (b)(4)(i) of this section, if November 1 is not a business 

day, then such allowance-holding deadline shall be midnight of the 

first business day thereafter.

(5) After November 1 (or the date described in paragraph (b)(4)(ii) 

of this section) immediately after the promulgation of each notice of 

data availability required in paragraph (b)(2)(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 determine whether the owners and operators 

described in paragraph (b)(3) of this section hold, in the assurance

account for the appropriate TR NOX Annual sources, TR NOX Annual 

units, and State (and Indian country within the borders of such 

State) established under paragraph (b)(3) of this section, the amount 

of TR NOX Annual allowances available under paragraph (a) of this 

section that the owners and operators are required to hold with 

regard to such sources, units, and State (and Indian country within 

the borders of such State) as calculated by the Administrator and 

referenced in the notice required in paragraph (b)(2)(iii)(B) of this 

section.
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(6) Notwithstanding any other provision of this subpart and any 

revision, made by or submitted to the Administrator after the 

promulgation of the notice of data availability required in paragraph 

(b)(2)(iii)(B) of this section for a control period in a given year, 

of any data used in making the calculations referenced in such 

notice, the amounts of TR NOX Annual allowances that the owners and 

operators are required to hold in accordance with §97.406(c)(2)(i) 

for such control period shall continue to be such amounts as 

calculated by the Administrator and referenced in such notice 

required in paragraph (b)(2)(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 and operators are 

required to hold in accordance with the calculation formula in 

§97.406(c)(2)(i) for such control period with regard to the TR NOX

Annual sources, TR NOX Annual units, and State (and Indian country 

within the borders of such State) involved, provided that such 

litigation under part 78 of this chapter, or the proceeding under 

part 78 of this chapter that resulted in the decision appealed in 
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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)(iii)(B) of this section.

(ii) If any such data are revised by the owners and operators of a TR 

NOX Annual source and TR NOX Annual unit whose designated 

representative submitted such data under paragraph (b)(2)(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 and operators are required to hold in accordance with the 

calculation formula in §97.406(c)(2)(i) for such control period with 

regard to the TR NOX Annual sources, TR NOX Annual units, and State 

(and Indian country within the borders of such State) involved, 

provided that such litigation was initiated no later than 30 days 

after promulgation of such notice required in paragraph 

(b)(2)(iii)(B) of this section.

(iii) If the revised data are used to recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this section, the amount of TR NOX

Annual allowances that the owners and operators are required to hold 

for such control period with regard to the TR NOX Annual sources, TR 

NOX Annual units, and State (and Indian country within the borders of 

such State) involved—
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(A) Where the amount of TR NOX Annual allowances that the owners and 

operators are 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 owners and operators shall hold the 

additional amount of TR NOX Annual allowances in the assurance account 

established by the Administrator for the appropriate TR NOX Annual 

sources, TR NOX Annual units, and State (and Indian country within the 

borders of such State) under paragraph (b)(3) of this section. The 

owners’ and operators’ failure to hold such additional amount, as 

required, before the new deadline shall not be a violation of the 

Clean Air Act. The owners’ and operators’ 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 

owners and operators fail to hold as required as of the new deadline, 

and each day in such control period, shall be a separate violation of 

the Clean Air Act. 

(B) For the owners and operators 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 all accounts 

from which TR NOX Annual allowances were transferred by such owners 

and operators for such control period to the assurance account 

established by the Administrator for the appropriate at TR NOX Annual 

sources, TR NOX Annual units, and State (and Indian country within the 

borders of such State) under paragraph (b)(3) of this section, a
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total amount of the TR NOX Annual allowances held in such assurance 

account equal to the amount of the decrease. If TR NOX Annual 

allowances were transferred to such assurance account from more than 

one account, the amount of TR NOX Annual allowances recorded in each 

such transferor account will be in proportion to the percentage of 

the total amount of TR NOX Annual allowances transferred to such 

assurance account for such control period from such transferor 

account. 

(C) Each TR NOX Annual allowance held under paragraph (b)(6)(iii)(A) 

of this section as a result of recalculation of requirements under 

the TR NOX Annual assurance provisions for such control period must be 

a TR NOX Annual allowance allocated for a control period in a year

before or the year immediately following, or in the same year as, the 

year of such control period. 

§ 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, or 97.428.
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§ 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 compliance account or an 

assurance 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 
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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 
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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 after the date on which the unit commences 

commercial operation; 

(3) 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 controls is completed after the applicable deadline under 
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paragraph (b)(1) or (2) of this section shall meet the requirements 

of §§75.4(e)(1) through (e)(4) of this chapter, except that:

(i) Such requirements shall apply to the monitoring systems required 

under §97.430 through §97.435, rather than the monitoring systems 

required under part 75 of this chapter;

(ii) NOX emission rate, NOX concentration, stack gas moisture content, 

stack gas volumetric flow rate, and O2 or CO2 concentration data shall 

be determined and reported, rather than the data listed in 

§75.4(e)(2) of this chapter; and

(iii) Any petition for another procedure under §75.4(e)(2) of this 

chapter shall be submitted under §97.435, rather than §75.66.

(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, 
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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 to the 

atmosphere without accounting for all such NOX 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 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 
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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 
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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 
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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 

quality-assurance and quality-control requirements of §75.21 of this 

chapter or appendix B to part 75 of this chapter, the owner or 
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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, 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 
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“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 
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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 
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the specified date, then the Administrator may issue a notice of 

disapproval under paragraph (d)(3)(iv)(C) of this section. 

(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:
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(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.
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(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 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.
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(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 
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or any State or 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).
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(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; or

(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 
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commence in the quarter covering January 1, 2012 through March 31, 

2012.

(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 
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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 
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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. 

(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;
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(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.

75. Part 97 is amended by adding subpart BBBBB to read as follows:

Subpart BBBBB—TR NOX Ozone Season Trading Program 

97.501 Purpose.

97.502 Definitions.

97.503 Measurements, abbreviations, and acronyms.

97.504 Applicability.

97.505 Retired unit exemption.
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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 setasides, Indian country 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 to 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.
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97.518 Delegation by designated representative and alternate 

designated representative.

97.519 [Reserved]

97.520 Establishment of compliance accounts and general 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.
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97.533 Notifications concerning monitoring.

97.534 Recordkeeping and reporting.

97.535 Petitions for alternatives to monitoring, recordkeeping, or 

reporting requirements.

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 §52.38 of this chapter, as a means of mitigating interstate 

transport of ozone 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 multi-state 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 
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Markets Division (or its successor determined by the Administrator) 

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, State, or 

permitting authority, in accordance with this subpart and any SIP 

revision submitted by the State and approved by the Administrator 

under §52.38(b)(3), (4), or (5) of this chapter, of the amount of 

such TR NOX Ozone Season allowances to be initially credited, at no 

cost to the recipient, to:

(1) A TR NOX Ozone Season unit;

(2) A new unit set-aside;

(3) An Indian country new unit set-aside; or

(4) An entity not listed in paragraphs (1) through (3) of this 

definition;

(5) Provided that, if the Administrator, State, or permitting 

authority initially credits, to a TR NOX Ozone Season unit qualifying 

for an initial credit, a credit in the amount of zero TR NOX Ozone 

Season allowances, the TR NOX Ozone Season unit will be treated as 

being allocated an amount (i.e., zero) of TR NOX Ozone Season 

allowances. 
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Allowable NOX emission rate means, for a unit, the most stringent 

State or federal NOX emission rate limit (in lb/MWhr or, if in 

lb/mmBtu, converted to lb/MWhr by multiplying it by the unit’s heat 

rate in mmBtu/MWhr) 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, recorded, held, deducted, or 

transferred only as whole allowances. 

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 in a given 

year, 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 §§97.506 and 97.524.
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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 the 

respective program. 

Assurance account means an Allowance Management System account, 

established by the Administrator under §97.525(b)(3) for certain 

owners and operators of a group of one or more TR NOX Ozone Season

sources and units in a given State (and Indian country within the 

borders of such State), in which are held TR NOX Ozone Season

allowances available for use for a control period in a given year in 

complying with the TR NOX Ozone Season assurance provisions in 

accordance with §§97.506 and 97.525. 

Authorized account representative means, for 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, for a TR NOX Ozone Season source’s 

compliance account, the designated representative of the source.
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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-
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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.

Business day means a day that does not fall on a weekend or a federal 

holiday.

Certifying official means a natural person who is:

(1) For a corporation, a president, secretary, treasurer, or vicepresident of 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.
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Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.

Coal means “coal” as defined in §72.2 of this chapter.

Coal-derived fuel means any fuel (whether in a solid, liquid, or 

gaseous state) produced by the mechanical, thermal, or chemical 

processing of coal.

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 that is a toppingcycle unit or a bottoming-cycle unit:

(1) Operating as part of a cogeneration system; and

(2) Producing on an annual average basis—

(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 than 42.5 percent of total energy input, 
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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 requirements in paragraph (2) of this 

definition shall not apply to a calendar year referenced in paragraph 

(2) of this definition during which the unit did not operate at all;

(4) 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

(5) Provided that, if, throughout its operation during the 12-month 

period or a calendar year referenced in paragraph (2) of this 

definition, a unit is operated as part of a cogeneration system and 

the cogeneration system meets on a system-wide basis the requirement 

in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall 

be deemed to meet such requirement during that 12-month period or 

calendar year. 

Combustion turbine means an enclosed device comprising:
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(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 January 1, 2005 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 or 

is moved to a new location or 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 January 1, 2005 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 
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the same or a different 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 January 1, 2005 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 or is 

moved to a different location or 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 or 

a different source, such date shall remain the replaced unit's date 

of commencement of commercial operation, and the replacement unit 
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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.

Common designated representative means, with regard to a control 

period in a given year, a designated representative where, as of 

April 1 immediately after the allowance transfer deadline for such 

control period, the same natural person is authorized under 

§§97.513(a) and 97.515(a) as the designated representative for a 

group of one or more TR NOX Ozone Season sources and units located in 

a State (and Indian country within the borders of such State).

Common designated representative’s assurance level means, with regard 

to a specific common designated representative and a State (and 

Indian country within the borders of such State) and control period 

in a given year for which the State assurance level is exceeded as 

described in §97.506(c)(2)(iii), the common designated 

representative’s share of the State NOX Ozone Season trading budget 

with the variability limit for the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative for a control period in a 

given year:

(1) With regard to a total amount of NOX emissions from all TR NOX

Ozone Season units in a State (and Indian country within the borders 
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of such State) during such control period, the total tonnage of NOX

emissions during such control period from a group of one or more TR 

NOX Ozone Season units located in such State (and such Indian country) 

and having the common designated representative for such control 

period; 

(2) With regard to a State NOX Ozone Season trading budget with the 

variability limit for such control period, the amount (rounded to the 

nearest allowance) equal to the sum of the total amount of TR NOX

Ozone Season allowances allocated for such control period to a group 

of one or more TR NOX Ozone Season units located in the State (and 

Indian country within the borders of such State) and having the 

common designated representative for such control period and of the 

total amount of TR NOX Ozone Season allowances purchased by an owner 

or operator of such TR NOX Ozone Season units in an auction for such 

control period and submitted by the State or the permitting authority 

to the Administrator for recordation in the compliance accounts for 

such TR NOX Ozone Season units in accordance with the TR NOX Ozone 

Season allowance auction provisions in a SIP revision approved by the 

Administrator under §52.38(b)(4) or (5) of this chapter, multiplied 

by the sum of the State NOX Ozone Season trading budget under 

§97.510(a) and the State’s variability limit under §97.510(b) for 

such control period and divided by such State NOX Ozone Season trading 

budget; 
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(3) Provided that, in the case of a unit that operates during, but 

has no amount of TR NOX Ozone Season allowances allocated under 

§§97.511 and 97.512 for, such 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 unit’s allowable NOX

emission rate applicable to such control period, multiplied by a 

capacity factor of 0.92 (if the unit is a boiler combusting any 

amount of coal or coal-derived fuel during such control period), 0.32

(if the unit is a simple combustion turbine during such control 

period), 0.71 (if the unit is a combined cycle turbine during such 

control period), 0.73 (if the unit is an integrated coal gasification 

combined cycle unit during such control period), or 0.44 (for any 

other unit), 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. 

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 to 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 a given year in complying 
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with the source's TR NOX Ozone Season emissions limitation in 

accordance with §§97.506 and 97.524. 

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 NOX-diluent) 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 
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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 
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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 the respective program. 

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:

(1) In accordance with this subpart; and

(2) With regard to a period before the unit or source is required to 

measure, record, and report such air pollutants in accordance with 

this subpart, in accordance with part 75 of this chapter.

Excess emissions means any ton of emissions from the TR NOX Ozone 

Season units at a TR NOX Ozone Season source during a control period 

in a given year that exceeds the TR NOX Ozone Season emissions 

limitation for the source for such control period.

Fossil fuel means—

(1) Natural gas, petroleum, coal, or any form of solid, liquid, or 

gaseous fuel derived from such material; or
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(2) For purposes of applying the limitation on “average annual fuel 

consumption of fossil fuel” in §§97.504(b)(2)(i)(B) and (ii), 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 2005 or any calendar year thereafter.

General account means an Allowance Management System account, 

established under this subpart, that is not a compliance account or 

an assurance account.

Generator means a device that produces electricity.

Gross electrical output means, for 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, for a unit for a specified period of time, the 

product (in mmBtu/time) of the gross calorific value of the fuel (in 

mmBtu/lb) fed into the unit multiplied by the fuel feed rate (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 
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derived from preheated combustion air, recirculated flue gases, or 

exhaust.

Heat input rate means, for a unit, the amount of heat input (in 

mmBtu) divided by unit operating time (in hr) or, for a unit and 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.

Heat rate means, for a unit, the unit’s maximum design heat input (in 

Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the unit’s 

maximum hourly load.

Indian country means “Indian country” as defined in 18 U.S.C. 1151.

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
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(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, for a unit, the maximum amount of 

fuel per hour (in Btu/hr) that the 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, rounded 

to the nearest tenth) 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 

that the generator is capable of producing on a steady state basis 

and during continuous operation (when not restricted by seasonal or 
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other deratings), such increased maximum amount (in MWe, rounded to 

the nearest tenth) as of such completion as specified by the person 

conducting the physical change.

Natural gas means “natural gas” as defined in §72.2 of this chapter.

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, for a TR NOX Ozone Season source or a TR NOX Ozone 

Season unit at a source respectively, any person who operates, 

controls, or supervises a TR NOX Ozone Season unit at the source or 

the TR NOX Ozone Season unit and shall include, but not be limited to, 

any holding company, utility system, or plant manager of such source 

or unit.

Owner means, for 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 
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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; and

(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. 

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, for a unit, 33 percent of 

the 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.
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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, auction, 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) The use of reject heat from electricity production in a useful 

thermal energy application or process; or

(2) 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.
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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 that is subject to the TR NOX Ozone 

Season 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.
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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, for a unit, total energy of all forms 

supplied to the 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, for a unit, 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 in accordance with 

subpart AAAAA of this part and §52.38(a) of this chapter (including 

such a program that is revised in a SIP revision approved by the 
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Administrator under §52.38(a)(3) or (4) of this chapter or that is 

established in a SIP revision approved by the Administrator under 

§52.38(a)(5) 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 or auctioned by the Administrator under this subpart, or by 

a State or permitting authority under a SIP revision approved by the 

Administrator under §52.38(b)(3), (4), or (5) of this chapter, to 

emit one ton of NOX during a control period of the specified calendar 

year for which the authorization is allocated or auctioned or of any 

calendar year thereafter under the TR NOX Ozone Season Trading 

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 from an assurance account (e.g., in order to account 

for compliance with the assurance provisions under §§97.506 and 

97.525). 

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:
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(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 in a given year 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 source means a source that includes one or more TR 

NOX Ozone Season units.

TR NOX Ozone Season Trading Program means a multi-state NOX air 

pollution control and emission reduction program established in 

accordance with this subpart and §52.38(b) of this chapter (including 

such a program that is revised in a SIP revision approved by the 

Administrator under §52.38(b)(3) or (4) of this chapter or that is 

established in a SIP revision approved by the Administrator under 

§52.38(b)(5) of this chapter), as a means of mitigating interstate 

transport of ozone and NOX.
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TR NOX Ozone Season unit means a unit that is subject to the TR NOX

Ozone Season Trading Program.

TR SO2 Group 1 Trading Program means a multi-state SO2 air pollution 

control and emission reduction program established in accordance with 

subpart CCCCC of this part and 52.39(a), (b), (d) through (f) , (j), 

and (k) of this chapter (including such a program that is revised in 

a SIP revision approved by the Administrator under §52.39(d) or (e) 

of this chapter or that is established in a SIP revision approved by 

the Administrator under §52.39(f) 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 in accordance with 

subpart DDDDD of this part and 52.39(a), (c), and (g) through (k) of 

this chapter (including such a program that is revised in a SIP 

revision approved by the Administrator under §52.39(g) or (h) of this 

chapter or that is established in a SIP revision approved by the 

Administrator under §52.39(i) of this chapter), as a means of 

mitigating interstate transport of fine particulates and SO2.

Unit means a stationary, fossil-fuel-fired boiler, stationary, 

fossil-fuel-fired combustion turbine, or other stationary, fossilfuel-fired combustion device. A unit that undergoes a physical 

change or is moved to a different location or source shall continue 

to be treated as the same unit. A unit (the replaced unit) that is 
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replaced by another unit (the replacement unit) at the same or a 

different source shall continue to be treated as the same unit, and 

the replacement unit shall be treated as a separate unit.

Unit operating day means, with regard to a unit, a calendar day in 

which the unit combusts any fuel.

Unit operating hour or hour of unit operation means, with regard to a 

unit, an hour in which the unit combusts any fuel.

Useful power means, with regard to a unit, electricity or mechanical 

energy that the 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).
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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
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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 (and Indian country within the 

borders of such 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-fuel-fired boiler or stationary, fossil-fuel-fired 

combustion turbine serving at any time, on or after January 1, 2005, 

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 
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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 (and Indian country within the borders of 

such 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) or (2)(i) of this section shall not be a 

TR NOX Ozone Season unit:

(1)(i) Any unit:

(A) Qualifying as a cogeneration unit throughout the later of 2005 or 

the 12-month period starting on the date the unit first produces 

electricity and continuing to qualify as a cogeneration unit

throughout each calendar year ending after the later of 2005 or such 

12-month period; and

(B) Not supplying in 2005 or any calendar year thereafter 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, after qualifying under paragraph (b)(1)(i) of this section 

as not being a TR NOX Ozone Season unit, a unit subsequently no longer 

meets all the requirements of paragraph (b)(1)(i) of this section, 

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 
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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. The unit 

shall thereafter continue to be a TR NOX Ozone Season unit. 

(2)(i) Any unit:

(A) Qualifying as a solid waste incineration unit throughout the 

later of 2005 or the 12-month period starting on the date the unit 

first produces electricity and continuing to qualify as a solid waste 

incineration unit throughout each calendar year ending after the 

later of 2005 or such 12-month period; and

(B) With an average annual fuel consumption of fossil fuel for the 

first 3 consecutive calendar years of operation starting no earlier 

than 2005 of less than 20 percent (on a Btu basis) and an average 

annual fuel consumption of fossil fuel for any 3 consecutive calendar 

years thereafter of less than 20 percent (on a Btu basis).

(ii) If, after qualifying under paragraph (b)(2)(i) of this section 

as not being a TR NOX Ozone Season unit, a unit subsequently no longer 

meets all the requirements of paragraph (b)(1)(i) of this section, 

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 2005 for 
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which the unit has an average annual fuel consumption of fossil fuel 

of 20 percent or more. The unit shall thereafter continue to be a TR 

NOX Ozone Season unit.

(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 or a SIP revision approved under §52.38(b)(4) or (5) of this 

chapter, 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 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 
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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 State or 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 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 
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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, 
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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 
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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 in a given year, 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 total NOX emissions during a control period in a given year 

from the TR NOX Ozone Season units at a TR NOX Ozone Season source are 

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

(B) The owners and operators of the source and each TR NOX Ozone 

Season unit at the source shall pay any fine, penalty, or assessment 

or comply with any other remedy imposed, for the same violations, 

under the Clean Air Act, and each ton of such excess emissions and 
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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 total NOX

emissions during a control period in a given year from all TR NOX

Ozone Season units at TR NOX Ozone Season sources in a State (and 

Indian country within the borders of such State) exceed the State 

assurance level, then the owners and operators of such sources and 

units in each group of one or more sources and units having a common 

designated representative for such control period, where the common 

designated representative’s share of such NOX emissions during such 

control period exceeds the common designated representative’s

assurance level for the State and such control period, shall hold (in 

the assurance account established for the owners and operators of 

such group) TR NOX Ozone Season allowances available for deduction for 

such control period under §97.525(a) in an amount equal to two times 

the product (rounded to the nearest whole number), as determined by 

the Administrator in accordance with §97.525(b), of multiplying—

(A) The quotient of the amount by which the common designated 

representative’s share of such NOX emissions exceeds the common 

designated representative’s assurance level divided by the sum of the 

amounts, determined for all common designated representatives for 

such sources and units in the State (and Indian country within the 

borders of such State) for such control period, by which each common 
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designated representative’s share of such NOX emissions exceeds the 

respective common designated representative’s assurance level; and

(B) The amount by which total NOX emissions from all TR NOX Ozone 

Season units at TR NOX Ozone Season sources in the State (and Indian 

country within the borders of such State) for such control period 

exceed the State assurance level. 

(ii) The owners and operators shall hold the TR NOX Ozone Season

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) Total NOX emissions from all TR NOX Ozone Season units at TR NOX

Ozone Season sources in a State (and Indian country within the 

borders of such State) during a control period in a given year exceed 

the State assurance level if such total NOX emissions exceed the sum, 

for such control period, of the State NOX Ozone Season trading budget 

under §97.510(a) and the State’s variability limit under §97.510(b).

(iv) It shall not be a violation of this subpart or of the Clean Air 

Act if total NOX emissions from all TR NOX Ozone Season units at TR 

NOX Ozone Season sources in a State (and Indian country within the 

borders of such State) during a control period exceed the State 

assurance level or if a common designated representative’s share of 
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total NOX emissions from the TR NOX Ozone Season units at TR NOX Ozone 

Season sources in a State (and Indian country within the borders of 

such State) during a control period exceeds the common designated 

representative’s assurance level. 

(v) To the extent the owners and operators fail to hold TR NOX Ozone 

Season allowances for a control period in a given year in accordance 

with paragraphs (c)(2)(i) through (iii) of this section, 

(A) The owners and operators 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 owners and operators 

fail to hold for such control period in accordance with paragraphs 

(c)(2)(i) through (iii) 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 under paragraphs (c)(1) and (c)(2) of this 

section for the control period starting on the later of May 1, 2012 

or the deadline for meeting the unit's monitor certification 

requirements under §97.530(b) and for each control period thereafter.

(4) Vintage of allowances held for compliance. (i) A TR NOX Ozone 

Season allowance held for compliance with the requirements under 
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paragraph (c)(1)(i) of this section for a control period in a given 

year must be a TR NOX Ozone Season allowance that was allocated for 

such control period or a control period in a prior year.

(ii) A TR NOX Ozone Season allowance held for compliance with the 

requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through (iii) 

of this section for a control period in a given year must be a TR NOX

Ozone Season allowance that was allocated for a control period in a 

prior year or the control period in the given year or in the 

immediately following year. 

(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. A TR NOX Ozone Season allowance is a 

limited authorization to emit one ton of NOX during the control period 

in one year. Such authorization is limited in its use and duration 

as follows:

(i) Such authorization shall only be used in accordance with the TR 

NOX Ozone Season Trading Program; and

(ii) Notwithstanding any other provision of this subpart, the 

Administrator has the authority to terminate or limit the use and 

duration of such authorization to the extent the Administrator 
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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. 
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(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 certificate of representation 

and 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.
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(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, except as provided in 

§97.518. 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 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.
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(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, is not a business day, 

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, 

Indian country new unit set-aside, and variability limits.

(a) The State NOX Ozone Season trading budgets, new unit set-asides, 

and Indian country new unit set-asides for allocations of TR NOX Ozone 

Season allowances for the control periods in 2012 and thereafter are 

as follows:
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State

NOX Ozone Season 

trading budget 

(tons)*

for 2012 and 2013

New unit setaside (tons)

for 2012 and 

2013

Indian country new 

unit set-aside 

(tons)

for 2012 and 2013

Alabama 31,746 635 ---

Arkansas 15,037 301 ---

Florida 27,825 529 28

Georgia 27,944 559 ---

Illinois 21,208 1,697 ---

Indiana 46,876 1,406 ---

Kentucky 36,167 1,447 ---

Louisiana 13,432 390 13

Maryland 7,179 144 ---

Mississippi 10,160 193 10

New Jersey 3,382 68 ---

New York 8,331 242 8

North Carolina 22,168 1,308 22

Ohio 40,063 801 ---

Pennsylvania 52,201 1,044 ---

South Carolina 13,909 264 14

Tennessee 14,908 298 ---

Texas 63,043 1,828 63

Virginia 14,452 723 ---

West Virginia 25,283 1,264 ---

State

NOX Ozone Season 

trading budget 

(tons)*

for 2014 and 

thereafter

New unit setaside (tons)

for 2014 and 

thereafter

Indian country 

new unit setaside (tons)

for 2014 and 

thereafter

Alabama 31,499 630 ---

Arkansas 15,037 301 ---

Florida 27,825 529 28

Georgia 18,279 366 ---

Illinois 21,208 1,697 ---
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Indiana 46,175 1,385 ---

Kentucky 32,674 1,307 ---

Louisiana 13,432 390 13

Maryland 7,179 144 ---

Mississippi 10,160 193 10

New Jersey 3,382 68 ---

New York 8,331 242 8

North Carolina 18,455 1,089 18

Ohio 37,792 756 ---

Pennsylvania 51,912 1,038 ---

South Carolina 13,909 264 14

Tennessee 8,016 160 ---

Texas 63,043 1,828 63

Virginia 14,452 723 ---

West Virginia 23,291 1,165 ---

* Each trading budget includes the new unit set-aside and, where 

applicable, the Indian country new unit set-aside and does not 

include the variability limit.

(b) The States’ variability limits for the State NOX Ozone Season

trading budgets for the control periods in 2012 and thereafter are as 

follows:

State

Variability limits

for 2012 and 2013

Variability limits

for 2014 and thereafter

Alabama 6,667 6,615

Arkansas 3,158 3,158

Florida 5,843 5,843

Georgia 5,868 3,839

Illinois 4,454 4,454

Indiana 9,844 9,697

Kentucky 7,595 6,862
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Louisiana 2,821 2,821

Maryland 1,508 1,508

Mississippi 2,134 2,134

New Jersey 710 710

New York 1,750 1,750

North Carolina 4,655 3,876

Ohio 8,413 7,936

Pennsylvania 10,962 10,902

South Carolina 2,921 2,921

Tennessee 3,131 1,683

Texas 13,239 13,239

Virginia 3,035 3,035

West Virginia 5,309 4,891

§ 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 provided 

in a notice of data availability issued by the Administrator. 

Providing an allocation to a unit in such notice does not constitute 

a determination that the unit is a TR NOX Ozone Season unit, and not 

providing an allocation to a unit in such notice 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 

provided an allocation in the notice of data availability issued 

under paragraph (a)(1) of this section does not operate, starting 

after 2011, during the control period in two consecutive years, such 

unit will not be allocated the TR NOX Ozone Season allowances provided 
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in such notice for the unit for the control periods in the fifth year 

after the first such year and in each year after that fifth 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 State where such unit is located and 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) New unit set-asides. (i) By June 1, 2012 and 

June 1 of each year thereafter, the Administrator will calculate the 

TR NOX Ozone Season allowance allocation to each TR NOX Ozone Season

unit in a State, in accordance with §97.512(a)(2) through (7) and 

(12), for the control period in the year of the applicable 

calculation deadline under this paragraph and will promulgate a 

notice of data availability of the results of the calculations.

(ii) For each notice of data availability required in paragraph 

(b)(1)(i) of this section, the Administrator will provide an 

opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR NOX Ozone Season units) are in 
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accordance with §97.512(a)(2) through (7) and (12) and §§97.506(b)(2) 

and 97.530 through 97.535. 

(B) The Administrator will adjust the calculations to the extent 

necessary to ensure that they are in accordance with the provisions 

referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(1)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.512(a)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) of this section. 

(iii) If the new unit set-aside for such control period contains any 

TR NOX Ozone Season allowances that have not been allocated in the 

applicable notice of data availability required in paragraph 

(b)(1)(ii) of this section, the Administrator will promulgate, by 

September 15 immediately after such notice, a notice of data 

availability that identifies any TR NOX Ozone Season units that 

commenced commercial operation during the period starting May 1 of 

the year before the year of such control period and ending August 31 

of year of such control period.

(iv) For each notice of data availability required in paragraph 

(b)(1)(iii) of this section, the Administrator will provide an 
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opportunity for submission of objections to the identification of TR 

NOX Ozone Season units in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR NOX Ozone Season units in such notice is in accordance with 

paragraph (b)(1)(iii) of this section. 

(B) The Administrator will adjust the identification of TR NOX Ozone 

Season units in the each notice of data availability required in 

paragraph (b)(1)(iii) of this section to the extent necessary to 

ensure that it is in accordance with paragraph (b)(1)(iii) of this 

section and will calculate the TR NOX Ozone Season allowance 

allocation to each TR NOX Ozone Season unit in accordance with 

§97.512(a)(9), (10), and (12) and §§97.506(b)(2) and 97.530 through 

97.535. By November 15 immediately after the promulgation of each 

notice of data availability required in paragraph (b)(1)(iii) of this 

section, the Administrator will promulgate a notice of data 

availability of any adjustments of the identification of TR NOX Ozone 

Season units that the Administrator determines to be necessary, the 

reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(1)(iv)(A) of this section, and the 

results of such calculations.
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(v) To the extent any TR NOX Ozone Season allowances are added to the 

new unit set-aside after promulgation of each notice of data 

availability required in paragraph (b)(1)(iv) of this section, the 

Administrator will promulgate additional notices of data 

availability, as deemed appropriate, of the allocation of such TR NOX

Ozone Season allowances in accordance with §97.512(a)(10). 

(2) Indian country new unit set-asides. (i) By June 1, 2012 and June

1 of each year thereafter, the Administrator will calculate the TR NOX

Ozone Season allowance allocation to each TR NOX Ozone Season unit in 

Indian country within the borders of a State, in accordance with 

§97.512(b)(2) through (7) and (12), for the control period in the 

year of the applicable calculation deadline under this paragraph and 

will promulgate a notice of data availability of the results of the 

calculations.

(ii) For each notice of data availability required in paragraph 

(b)(2)(i) of this section, the Administrator will provide an 

opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR NOX Ozone Season units) are in 
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accordance with §97.512(b)(2) through (7) and (12) and §§97.506(b)(2) 

and 97.530 through 97.535. 

(B) 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)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.512(b)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) of this section. 

(iii) If the Indian country new unit set-aside for such control 

period contains any TR NOX Ozone Season allowances that have not been 

allocated in the applicable notice of data availability required in 

paragraph (b)(2)(ii) of this section, the Administrator will 

promulgate, by September 15 immediately after such notice, a notice 

of data availability that identifies any TR NOX Ozone Season units 

that commenced commercial operation during the period starting May 1 

of the year before the year of such control period and ending August 

31 of year of such control period.

(iv) For each notice of data availability required in paragraph 

(b)(2)(iii) of this section, the Administrator will provide an 
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opportunity for submission of objections to the identification of TR 

NOX Ozone Season units in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR NOX Ozone Season units in such notice is in accordance with 

paragraph (b)(2)(iii) of this section. 

(B) The Administrator will adjust the identification of TR NOX Ozone 

Season units in the each notice of data availability required in 

paragraph (b)(2)(iii) of this section to the extent necessary to 

ensure that it is in accordance with paragraph (b)(2)(iii) of this 

section and will calculate the TR NOX Ozone Season allowance 

allocation to each TR NOX Ozone Season unit in accordance with 

§97.512(b)(9), (10), and (12) and §§97.506(b)(2) and 97.530 through 

97.535. By November 15 immediately after the promulgation of each 

notice of data availability required in paragraph (b)(2)(iii) of this 

section, the Administrator will promulgate a notice of data 

availability of any adjustments of the identification of TR NOX Ozone 

Season units that the Administrator determines to be necessary, the 

reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(2)(iv)(A) of this section, and the 

results of such calculations. 
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(v) To the extent any TR NOX Ozone Season allowances are added to the 

Indian country new unit set-aside after promulgation of each notice 

of data availability required in paragraph (b)(2)(iv) of this

section, the Administrator will promulgate additional notices of data 

availability, as deemed appropriate, of the allocation of such TR NOX

Ozone Season allowances in accordance with §97.512(b)(10). 

(c) Units incorrectly allocated TR NOX Ozone Season allowances. (1) 

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, or under a provision of a SIP revision 

approved under §52.38(b)(3), (4), or (5) of this chapter, where such 

control period and the recipient are covered by the provisions of 

paragraph (c)(1)(i) of this section or were allocated under 

§97.512(a)(2) through (7), (9), and (12) and (b)(2) through (7), (9), 

and (12), or under a provision of a SIP revision approved under 

§52.38(b)(4) or (5) of this chapter, where such control period and 

the recipient are covered by the provisions of paragraph (c)(1)(ii) 

of this section, then the Administrator will notify the designated 

representative of the recipient and will act in accordance with the 

procedures set forth in paragraphs (c)(2) through (5) of this 

section:

(i)(A) The recipient is not actually a TR NOX Ozone Season unit under 

§97.504 as of May 1, 2012 and is allocated TR NOX Ozone Season 

allowances for such control period or, in the case of an allocation 
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under a provision of a SIP revision approved under §52.38(b)(3), (4), 

or (5) of this chapter, the recipient is not actually a TR NOX Ozone 

Season unit as of May 1, 2012 and is allocated TR NOX Ozone Season 

allowances for such control period that the SIP revision provides 

should be allocated only to recipients that are TR NOX Ozone Season 

units as of May 1, 2012; or

(B) The recipient is not located as of May 1 of the control period in 

the State from whose NOX Ozone Season trading budget the TR NOX Ozone 

Season allowances allocated under paragraph (a) of this section, or 

under a provision of a SIP revision approved under §52.38(b)(3), (4), 

or (5) of this chapter, were allocated for such control period. 

(ii) The recipient is not actually a TR NOX Ozone Season unit under 

§97.504 as of May 1 of such control period and is allocated TR NOX

Ozone Season allowances for such control period or, in the case of an 

allocation under a provision of a SIP revision approved under 

§52.38(b)(3), (4), or (5) of this chapter, the recipient is not 

actually a TR NOX Ozone Season unit as of January 1 of such control 

period and is allocated TR NOX Ozone Season allowances for such 

control period that the SIP revision provides should be allocated 

only to recipients that are TR NOX Ozone Season units as of May 1 of 

such control period. 
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(2) Except as provided in paragraph (c)(3) or (4) of this section, 

the Administrator will not record such TR NOX Ozone Season allowances 

under §97.521.

(3) If the Administrator already recorded such TR NOX Ozone Season

allowances under §97.521 and if the Administrator makes the

determination under paragraph (c)(1) of this section 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 

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.

(4) If the Administrator already recorded such TR NOX Ozone Season

allowances under §97.521 and if the Administrator makes the

determination under paragraph (c)(1) of this section 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. 
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(5)(i) With regard to the TR NOX Ozone Season allowances that are not 

recorded, or that are deducted as an incorrect allocation, in 

accordance with paragraphs (c)(2) and (3) of this section for a 

recipient under paragraph (c)(1)(i) of this section, the 

Administrator will:

(A) Transfer such TR NOX Ozone Season allowances to the new unit setaside for such control period for the State from whose NOX Ozone 

Season trading budget the TR NOX Ozone Season allowances were 

allocated; or

(B) If the State has a SIP revision approved under §52.38(b)(4) or 

(5) covering such control period, include such TR NOX Annual 

allowances in the portion of the State NOX Ozone Season trading budget 

that may be allocated for such control period in accordance with such 

SIP revision. 

(ii) With regard to the TR NOX Ozone Season allowances that were not 

allocated from the Indian country new unit set-aside for such control 

period and that are not recorded, or that are deducted as an 

incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 

this section for a recipient under paragraph (c)(1)(ii) of this 

paragraph, the Administrator will:

(A) Transfer such TR NOX Ozone Season allowances to the new unit setaside for such control period; or
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(B) If the State has a SIP revision approved under §52.38(b)(4) or 

(5) covering such control period, include such TR NOX Ozone Season

allowances in the portion of the State NOX Ozone Season trading budget 

that may be allocated for such control period in accordance with such 

SIP revision. 

(iii) With regard to the TR NOX Ozone Season allowances that were 

allocated from the Indian country new unit set-aside for such control 

period and that are not recorded, or that are deducted as an 

incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 

this section for a recipient under paragraph (c)(1)(ii) of this 

paragraph, the Administrator will transfer such TR NOX Ozone Season

allowances to the Indian country new unit set-aside for such control 

period.

§ 97.512 TR NOX Ozone Season allowance allocations to new units.

(a) For each control period in 2012 and thereafter and for the TR NOX

Ozone Season units in each State, the Administrator will allocate TR 

NOX Ozone Season allowances to the TR NOX Ozone Season units as

follows:

(1) The TR NOX Ozone Season allowances will be allocated to the 

following TR NOX Ozone Season units, except as provided in paragraph 

(a)(10) of this section:
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(i) TR NOX Ozone Season units that are not allocated an amount of TR 

NOX Ozone Season allowances in the notice of data availability issued 

under §97.511(a)(1);

(ii) TR NOX Ozone Season units whose allocation of an amount of TR NOX

Ozone Season allowances for such control period in the notice of data 

availability issued under §97.511(a)(1) is covered by §97.511(c)(2) 

or (3);

(iii) TR NOX Ozone Season units that are allocated an amount of TR NOX

Ozone Season allowances for such control period in the notice of data 

availability issued under §97.511(a)(1), which allocation is 

terminated for such control period pursuant to §97.511(a)(2), and 

that operate during the control period immediately preceding such 

control period; or

(iv) For purposes of paragraph (a)(9) of this section, TR NOX Ozone 

Season units under §97.511(c)(1)(ii) whose allocation of an amount of

TR NOX Ozone Season allowances for such control period in the notice 

of data availability issued under §97.511(b)(1)(ii)(B) is covered by 

§97.511(c)(2) or (3). 

(2) The Administrator will establish a separate new unit set-aside 

for the State for each such control period. Each such new unit setaside will be allocated TR NOX Ozone Season allowances in an amount 

equal to the applicable amount of tons of NOX emissions as set forth 
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in §97.510(a) and will be allocated additional TR NOX Ozone Season

allowances (if any) in accordance with §§97.511(a)(2) and (c)(5) and 

paragraph (b)(10) of this section.

(3) The Administrator will determine, for each TR NOX Ozone Season

unit described in paragraph (a)(1) of this section, an allocation of 

TR NOX Ozone Season allowances for the later of the following control 

periods and for each subsequent control period:

(i) The control period in 2012;

(ii) The first control period after the control period in which the 

TR NOX Ozone Season unit commences commercial operation;

(iii) For a unit described in paragraph (a)(1)(ii) of this section, 

the first control period in which the TR NOX Ozone Season unit 

operates in the State after operating in another jurisdiction and for 

which the unit is not already allocated one or more TR NOX Ozone 

Season allowances; and

(iv) For a unit described in paragraph (a)(1)(iii) of this section, 

the first control period after the control period in which the unit 

resumes operation. 

(4)(i) The allocation to each TR NOX Ozone Season unit described in 

paragraph (a)(1)(i) through (iii) of this section and for each 

control period described in paragraph (a)(3) of this section will be 
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an amount equal to the unit’s total tons of NOX emissions during the 

immediately preceding control period.

(ii) The Administrator will adjust the allocation amount in paragraph 

(a)(4)(i) in accordance with paragraphs (a)(5) through (7) and (12)

of this section.

(5) The Administrator will calculate the sum of the TR NOX Ozone 

Season allowances determined for all such TR NOX Ozone Season units 

under paragraph (a)(4)(i) of this section in the State for such 

control period.

(6) If the amount of TR NOX Ozone Season allowances in the new unit 

set-aside for the State for such control period is greater than or 

equal to the sum under paragraph (a)(5) of this section, then the 

Administrator will allocate the amount of TR NOX Ozone Season

allowances determined for each such TR NOX Ozone Season unit under

paragraph (a)(4)(i) of this section.

(7) If the amount of TR NOX Ozone Season allowances in the new unit 

set-aside for the State for such control period is less than the sum 

under paragraph (a)(5) of this section, then the Administrator will 

allocate to each such TR NOX Ozone Season unit the amount of the TR 

NOX Ozone Season allowances determined under paragraph (a)(4)(i) of 

this section for the unit, multiplied by the amount of TR NOX Ozone 

Season allowances in the new unit set-aside for such control period, 
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divided by the sum under paragraph (a)(5) of this section, and 

rounded to the nearest allowance.

(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.511(b)(1)(i) and (ii), of the amount of TR NOX Ozone Season

allowances allocated under paragraphs (a)(2) through (7) and (12) of 

this section for such control period to each TR NOX Ozone Season unit 

eligible for such allocation.

(9) If, after completion of the procedures under paragraphs (a)(5) 

through (8) of this section for such control period, any unallocated 

TR NOX Ozone Season allowances remain in the new unit set-aside for 

the State for such control period, the Administrator will allocate 

such TR NOX Ozone Season allowances as follows--

(i) The Administrator will determine, for each unit described in 

paragraph (a)(1) of this section that commenced commercial operation 

during the period starting May 1 of the year before the year of such 

control period and ending August 31 of year of such control period, 

the positive difference (if any) between the unit’s emissions during 

such control period and the amount of TR NOX Ozone Season allowances 

referenced in the notice of data availability required under 

§97.511(b)(1)(ii) for the unit for such control period;
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(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (a)(9)(i) of this section;

(iii) If the amount of unallocated TR NOX Ozone Season allowances 

remaining in the new unit set-aside for the State for such control 

period is greater than or equal to the sum determined under paragraph 

(a)(9)(ii) of this section, then the Administrator will allocate the 

amount of TR NOX Ozone Season allowances determined for each such TR 

NOX Ozone Season unit under paragraph (a)(9)(i) of this section; and

(iv) If the amount of unallocated TR NOX Ozone Season allowances 

remaining in the new unit set-aside for the State for such control 

period is less than the sum under paragraph (a)(9)(ii) of this 

section, then the Administrator will allocate to each such TR NOX

Ozone Season unit the amount of the TR NOX Ozone Season allowances 

determined under paragraph (a)(9)(i) of this section for the unit, 

multiplied by the amount of unallocated TR NOX Ozone Season allowances 

remaining in the new unit set-aside for such control period, divided 

by the sum under paragraph (a)(9)(ii) of this section, and rounded to 

the nearest allowance.

(10) If, after completion of the procedures under paragraphs (a)(9) 

and (12) of this section for such control period, any unallocated TR 

NOX Ozone Season allowances remain in the new unit set-aside for the

State for such control period, the Administrator will allocate to 

each TR NOX Ozone Season unit that is in the State, is allocated an 
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amount of TR NOX Ozone Season allowances in the notice of data 

availability issued under §97.511(a)(1), 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 set-aside, 

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 sum of the 

amounts of tons in such new unit set-aside and the Indian country new 

unit set-aside for the State for such control period, and rounded to 

the nearest allowance.

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.511(b)(1)(iii), (iv), and (v), of the amount of TR NOX Ozone 

Season allowances allocated under paragraphs (a)(9), (10), and (12) 

of this section for such control period to each TR NOX Ozone Season 

unit eligible for such allocation.

(12)(i) Notwithstanding the requirements of paragraphs (a)(2) through 

(11) of this section, if the calculations of allocations of a new 

unit set-aside for a control period in a given year under paragraph 

(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this 

section, or paragraphs (a)(6), (9)(iii), and (10) of this section 

would otherwise result in total allocations of such new unit set-
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aside exceeding the total amount of such new unit set-aside, then the 

Administrator will adjust the results of the calculations under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 

follows. The Administrator will list the TR NOX Ozone Season units in 

descending order based on the amount of such units’ allocations under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, 

and, in cases of equal allocation amounts, in alphabetical order of 

the relevant source’s name and numerical order of the relevant unit’s 

identification number, and will reduce each unit’s allocation under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, by 

one TR NOX Ozone Season allowance (but not below zero) in the order in 

which the units are listed and will repeat this reduction process as 

necessary, until the total allocations of such new unit set-aside 

equal the total amount of such new unit set-aside. 

(ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 

of this section, if the calculations of allocations of a new unit 

set-aside for a control period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section would otherwise result in 

a total allocations of such new unit set-aside less than the total 

amount of such new unit set-aside, then the Administrator will adjust 

the results of the calculations under paragraph (a)(10) of this 

section, as follows. The Administrator will list the TR NOX Ozone 

Season units in descending order based on the amount of such units’ 

allocations under paragraph (a)(10) of this section and, in cases of 
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equal allocation amounts, in alphabetical order of the relevant 

source’s name and numerical order of the relevant unit’s 

identification number, and will increase each unit’s allocation under 

paragraph (a)(10) of this section by one TR NOX Ozone Season allowance 

in the order in which the units are listed and will repeat this 

increase process as necessary, until the total allocations of such 

new unit set-aside equal the total amount of such new unit set-aside. 

(b) For each control period in 2012 and thereafter and for the TR NOX

Ozone Season units located in Indian country within the borders of 

each State, the Administrator will allocate TR NOX Ozone Season

allowances to the TR NOX Ozone Season units as follows: 

(1) The TR NOX Ozone Season allowances will be allocated to the 

following TR NOX Ozone Season units, except as provided in paragraph 

(b)(10) of this section:

(i) TR NOX Ozone Season units that are not allocated an amount of TR 

NOX Ozone Season allowances in the notice of data availability issued 

under §97.511(a)(1); or

(ii) For purposes of paragraph (b)(9) of this section, TR NOX Ozone 

Season units under §97.511(c)(1)(ii) whose allocation of an amount of

TR NOX Ozone Season allowances for such control period in the notice 

of data availability issued under §97.511(b)(2)(ii)(B) is covered by 

§97.511(c)(2) or (3). 
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(2) The Administrator will establish a separate Indian country new 

unit set-aside for the State for each such control period. Each such 

Indian country 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) and will be allocated 

additional TR NOX Ozone Season allowances (if any) in accordance with 

§97.511(c)(5).

(3) The Administrator will determine, for each TR NOX Ozone Season

unit described in paragraph (b)(1) of this section, an allocation of 

TR NOX Ozone Season allowances for the later of the following control 

periods and for each subsequent control period:

(i) The control period in 2012; and

(ii) The first control period after the control period in which the 

TR NOX Ozone Season unit commences commercial operation.

(4)(i) The allocation to each TR NOX Ozone Season unit described in 

paragraph (b)(1)(i) of this section and for each control period 

described in paragraph (b)(3) of this section will be an amount equal 

to the unit’s total tons of NOX emissions during the immediately 

preceding control period.

(ii) The Administrator will adjust the allocation amount in paragraph 

(b)(4)(i) in accordance with paragraphs (b)(5) through (7) and (12)

of this section.
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(5) The Administrator will calculate the sum of the TR NOX Ozone 

Season allowances determined for all such TR NOX Ozone Season units 

under paragraph (b)(4)(i) of this section in Indian country within 

the borders of the State for such control period.

(6) If the amount of TR NOX Ozone Season allowances in the Indian 

country new unit set-aside for the State for such control period is 

greater than or equal to the sum under paragraph (b)(5) of this 

section, then the Administrator will allocate the amount of TR NOX

Ozone Season allowances determined for each such TR NOX Ozone Season

unit under paragraph (b)(4)(i) of this section.

(7) If the amount of TR NOX Ozone Season allowances in the Indian 

country new unit set-aside for the State for such control period is 

less than the sum under paragraph (b)(5) of this section, then the 

Administrator will allocate to each such TR NOX Ozone Season unit the 

amount of the TR NOX Ozone Season allowances determined under 

paragraph (b)(4)(i) of this section for the unit, multiplied by the 

amount of TR NOX Ozone Season allowances in the Indian country new 

unit set-aside for such control period, divided by the sum under 

paragraph (b)(5) of this section, and rounded to the nearest 

allowance.

(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.511(b)(2)(i) and (ii), of the amount of TR NOX Ozone Season
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allowances allocated under paragraphs (b)(2) through (7) and (12) of 

this section for such control period to each TR NOX Ozone Season unit 

eligible for such allocation.

(9) If, after completion of the procedures under paragraphs (b)(5) 

through (8) of this section for such control period, any unallocated 

TR NOX Ozone Season allowances remain in the Indian country new unit 

set-aside for the State for such control period, the Administrator 

will allocate such TR NOX Ozone Season allowances as follows--

(i) The Administrator will determine, for each unit described in 

paragraph (b)(1) of this section that commenced commercial operation 

during the period starting May 1 of the year before the year of such 

control period and ending August 31 of year of such control period, 

the positive difference (if any) between the unit’s emissions during 

such control period and the amount of TR NOX Ozone Season allowances 

referenced in the notice of data availability required under 

§97.511(b)(2)(ii) for the unit for such control period;

(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (b)(9)(i) of this section;

(iii) If the amount of unallocated TR NOX Ozone Season allowances 

remaining in the Indian country new unit set-aside for the State for 

such control period is greater than or equal to the sum determined 

under paragraph (b)(9)(ii) of this section, then the Administrator 
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will allocate the amount of TR NOX Ozone Season allowances determined 

for each such TR NOX Ozone Season unit under paragraph (b)(9)(i) of 

this section; and

(iv) If the amount of unallocated TR NOX Ozone Season allowances 

remaining in the Indian country new unit set-aside for the State for 

such control period is less than the sum under paragraph (b)(9)(ii)

of this section, then the Administrator will allocate to each such TR 

NOX Ozone Season unit the amount of the TR NOX Ozone Season allowances 

determined under paragraph (b)(9)(i) of this section for the unit, 

multiplied by the amount of unallocated TR NOX Ozone Season allowances 

remaining in the Indian country new unit set-aside for such control 

period, divided by the sum under paragraph (b)(9)(ii) of this 

section, and rounded to the nearest allowance.

(10) If, after completion of the procedures under paragraphs (b)(9) 

and (12) of this section for such control period, any unallocated TR 

NOX Ozone Season allowances remain in the Indian country new unit setaside for the State for such control period, the Administrator will:

(i) Transfer such unallocated TR NOX Ozone Season allowances to the 

new unit set-aside for the State for such control period; or 

(ii) If the State has a SIP revision approved under §52.38(b)(4) or 

(5) covering such control period, include such unallocated TR NOX

Ozone Season allowances in the portion of the State NOX Ozone Season 
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trading budget that may be allocated for such control period in 

accordance with such SIP revision. 

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.511(b)(2)(iii), (iv), and (v), of the amount of TR NOX Ozone 

Season allowances allocated under paragraphs (b)(9), (10), and (12) 

of this section for such control period to each TR NOX Ozone Season 

unit eligible for such allocation.

(12)(i) Notwithstanding the requirements of paragraphs (b)(2) through 

(11) of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 

paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) of 

this section, or paragraphs (b)(6), (9)(iii), and (10) of this 

section would otherwise result in total allocations of such Indian 

country new unit set-aside exceeding the total amount of such Indian 

country new unit set-aside, then the Administrator will adjust the 

results of the calculations under paragraph (b)(7), (9)(iv), or (10) 

of this section, as applicable, as follows. The Administrator will 

list the TR NOX Ozone Season units in descending order based on the 

amount of such units’ allocations under paragraph (b)(7), (9)(iv), or 

(10) of this section, as applicable, and, in cases of equal 

allocation amounts, in alphabetical order of the relevant source’s 

name and numerical order of the relevant unit’s identification 

number, and will reduce each unit’s allocation under paragraph 
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(b)(7), (9)(iv), or (10) of this section, as applicable, by one TR NOX

Ozone Season allowance (but not below zero) in the order in which the 

units are listed and will repeat this reduction process as necessary, 

until the total allocations of such Indian country new unit set-aside 

equal the total amount of such Indian country new unit set-aside. 

(ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 

of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 

paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 

result in a total allocations of such Indian country new unit setaside less than the total amount of such Indian country new unit setaside, then the Administrator will adjust the results of the 

calculations under paragraph (b)(10) of this section, as follows. 

The Administrator will list the TR NOX Ozone Season units in 

descending order based on the amount of such units’ allocations under 

paragraph (b)(10) of this section and, in cases of equal allocation

amounts, in alphabetical order of the relevant source’s name and 

numerical order of the relevant unit’s identification number, and 

will increase each unit’s allocation under paragraph (b)(10) of this 

section by one TR NOX Ozone Season allowance in the order in which the 

units are listed and will repeat this increase process as necessary, 

until the total allocations of such Indian country new unit set-aside 

equal the total amount of such Indian country new unit set-aside. 
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§ 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 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 
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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 
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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” (as distinguished from 

the term “common 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 
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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; changes in units at 

the source.

(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.
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(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 

at the source 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 at the 

source, including the addition or removal of an owner or operator, 

the designated representative or any alternate designated 
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representative shall submit a revision to the certificate of 

representation under §97.516 amending the list of owners and 

operators to reflect the change.

(d) Changes in units at the source. Within 30 days of any change in 

which units are located at a TR NOX Ozone Season source (including the 

addition or removal of a unit), the designated representative or any 

alternate designated representative shall submit a certificate of 

representation under §97.516 amending the list of units to reflect 

the change. 

(1) If the change is the addition of a unit that operated (other than 

for purposes of testing by the manufacturer before initial 

installation) before being located at the source, then the 

certificate of representation shall identify, in a format prescribed 

by the Administrator, the entity from whom the unit was purchased or 

otherwise obtained (including name, address, telephone number, and 

facsimile number (if any)), the date on which the unit was purchased 

or otherwise obtained, and the date on which the unit became located 

at the source.

(2) If the change is the removal of a unit, then the certificate of 

representation shall identify, in a format prescribed by the 

Administrator, the entity to which the unit was sold or that 

otherwise obtained the unit (including name, address, telephone 

number, and facsimile number (if any)), the date on which the unit 
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was sold or otherwise obtained, and the date on which the unit became 

no longer located at the source. 

§ 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, actual or projected date of commencement of 

commercial operation, and a statement of whether such source is 

located in Indian Country. If a projected date of commencement of 

commercial operation is provided, the actual date of commencement of 

commercial operation shall be provided when such information becomes 

available.

(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.
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(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—

(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 decision or 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 
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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 
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certificate of representation under §97.516 is received by the 

Administrator.

(b) Except as provided in paragraph (a) of this section, 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 
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submission to the Administrator provided for or required under this 

subpart.

(c) In order to delegate authority to a natural person 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 in this section 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 
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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 
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representative or alternate designated representative submitting such 

notice of delegation.

§ 97.519 [Reserved]

§ 97.520 Establishment of compliance accounts, assurance accounts, 

and general 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 shall be the 

authorized account representative and the alternate authorized 

account representative respectively of the compliance account.

(b) Assurance accounts. The Administrator will establish assurance

accounts for certain owners and operators and States in accordance 

with §97.525(b)(3). 

(c) 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 
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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;
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(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 decision or order 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 
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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 decision or order issued to the authorized account representative 

or alternate authorized account representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph (c)(5) of this section 

concerning delegation of authority to make submissions, each 
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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.
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(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 (c)(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 (c)(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 Ozone Season allowances in the general account.
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(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 or removal of a 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 (c)(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.
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(ii) Except as provided in paragraph (c)(4)(i) 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 
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authority to make an electronic submission to the Administrator 

provided for or required under this subpart.

(iii) In order to delegate authority to a natural person to make an 

electronic submission to the Administrator in accordance with 

paragraph (c)(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 in this section as an “agent”);

(C) For each such natural person, a list of the type or types of 

electronic submissions under paragraph (c)(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 
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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(c)(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(c)(5)(iv), I agree to maintain an email 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(c)(5) is terminated.”.

(iv) A notice of delegation submitted under paragraph (c)(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.
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(v) Any electronic submission covered by the certification in 

paragraph (c)(5)(iii)(D) of this section and made in accordance with 

a notice of delegation effective under paragraph (c)(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) Closing a general account. (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 30 days after the notice is sent.

The account will be closed after the 30-day period unless, before the 

end of the 30-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 
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demonstrating to the satisfaction of the Administrator good cause as 

to why the account should not be closed.

(d) Account identification. The Administrator will assign a unique 

identifying number to each account established under paragraph (a),

(b), or (c) of this section.

(e) Responsibilities of authorized account representative and 

alternate authorized account representative. After the establishment 

of a compliance account or general 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 (c)(2)(ii) and (c)(5) of this 

section. 

§ 97.521 Recordation of TR NOX Ozone Season allowance allocations and 

auction results.

(a) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR NOX Ozone Season

source's compliance account the TR NOX Ozone Season allowances 

allocated to the TR NOX Ozone Season units at the source in accordance 

with §97.511(a) for the control period in 2012.
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(b) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR NOX Ozone Season

source's compliance account the TR NOX Ozone Season allowances 

allocated to the TR NOX Ozone Season units at the source in accordance 

with §97.511(a) for the control period in 2013, unless the State in 

which the source is located notifies the Administrator in writing by 

[INSERT DATE 70 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] of the State’s intent to submit to the Administrator a 

complete SIP revision by April 1, 2012 meeting the requirements of 

§52.38(b)(3)(i) through (iv) of this chapter.

(1) If, by April 1, 2012, the State does not submit to the 

Administrator such complete SIP revision, the Administrator will 

record by April 15, 2012 in each TR NOX Ozone Season source's 

compliance account the TR NOX Ozone Season allowances allocated to the 

TR NOX Ozone Season units at the source in accordance with §97.511(a)

for the control period in 2013.

(2) If the State submits to the Administrator by April 1, 2012, and 

the Administrator approves by October 1, 2012, such complete SIP 

revision, the Administrator will record by October 1, 2012 in each TR 

NOX Ozone Season source's compliance account the TR NOX Ozone Season

allowances allocated to the TR NOX Ozone Season units at the source as 

provided in such approved, complete SIP revision for the control 

period in 2013.
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(3) If the State submits to the Administrator by April 1, 2012, and 

the Administrator does not approve by October 1, 2012, such complete 

SIP revision, the Administrator will record by October 1, 2012 in 

each TR NOX Ozone Season source's compliance account the TR NOX Ozone 

Season allowances allocated to the TR NOX Ozone Season units at the 

source in accordance with §97.511(a) for the control period in 2013.

(c) By July 1, 2013, the Administrator will record in each TR NOX

Ozone Season source's compliance account the TR NOX Ozone Season

allowances allocated to the TR NOX Ozone Season units at the source, 

or in each appropriate Allowance Management System account the TR NOX

Ozone Season allowances auctioned to TR NOX Ozone Season units, in 

accordance with §97.511(a), or with a SIP revision approved under 

§52.38(b)(4) or (5) of this chapter, for the control period in 2014 

and 2015.

(d) By July 1, 2014, the Administrator will record in each TR NOX

Ozone Season source's compliance account the TR NOX Ozone Season

allowances allocated to the TR NOX Ozone Season units at the source, 

or in each appropriate Allowance Management System account the TR NOX

Ozone Season allowances auctioned to TR NOX Ozone Season units, in 

accordance with §97.511(a), or with a SIP revision approved under 

§52.38(b)(4) or (5) of this chapter, for the control period in 2016 

and 2017.
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(e) By July 1, 2015, the Administrator will record in each TR NOX

Ozone Season source's compliance account the TR NOX Ozone Season

allowances allocated to the TR NOX Ozone Season units at the source, 

or in each appropriate Allowance Management System account the TR NOX

Ozone Season allowances auctioned to TR NOX Ozone Season units, in 

accordance with §97.511(a), or with a SIP revision approved under 

§52.38(b)(4) or (5) of this chapter, for the control period in 2018 

and 2019.

(f) By July 1, 2016 and July 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 to the 

TR NOX Ozone Season units at the source, or in each appropriate 

Allowance Management System account the TR NOX Ozone Season allowances

auctioned to TR NOX Ozone Season units, in accordance with §97.511(a), 

or with a SIP revision approved under §52.38(b)(4) or (5) of this 

chapter, for the control period in the fourth year after the year of 

the applicable recordation deadline under this paragraph.

(g) By August 1, 2012 and August 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 to the 

TR NOX Ozone Season units at the source, or in each appropriate 

Allowance Management System account the TR NOX Ozone Season allowances

auctioned to TR NOX Ozone Season units, in accordance with 

§97.512(a)(2) through (8) and (12), or with a SIP revision approved 
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under §52.38(b)(4) or (5) of this chapter, for the control period in 

the year of the applicable recordation deadline under this paragraph.

(h) By August 1, 2012 and August 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 to the 

TR NOX Ozone Season units at the source in accordance with 

§97.512(b)(2) through (8) and (12) for the control period in the year 

of the applicable recordation deadline under this paragraph.

(i) By November 15, 2012 and November 15 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 to the 

TR NOX Ozone Season units at the source in accordance with 

§97.512(a)(9) through (12), for the control period in the year of the 

applicable recordation deadline under this paragraph.

(j) By the date on which any allocation or auction results, other 

than an allocation or auction results described in paragraphs (a) 

through (i) of this section, of TR NOX Ozone Season allowances to a 

recipient is made by or are submitted to the Administrator in 

accordance with §97.511 or §97.512 or with a SIP revision approved 

under §52.38(b)(4) or (5) of this chapter, the Administrator will 

record such allocation or auction results in the appropriate 

Allowance Management System account. 
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(k) When recording the allocation or auction of TR NOX Ozone Season

allowances to a TR NOX Ozone Season unit or other entity in an 

Allowance Management System 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 or auctioned.

§ 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
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(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

that is correctly submitted under §97.522, 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 in the transfer. 

(b) A TR NOX Ozone Season allowance transfer to or from a compliance 

account 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 from such compliance account 

under §97.524 for the control period immediately before such 

allowance transfer deadline.

(c) Where a TR NOX Ozone Season allowance transfer is not correctly 

submitted under §97.522, the Administrator will not record such 

transfer.
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(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 non-recordation.

§ 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 such control period or a control period in a 

prior year; and

(2) Are held in the source’s compliance account as of the allowance 

transfer deadline for such control period. 
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(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 in a given year, 

the Administrator will deduct from each source’s 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 a 

given year 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 
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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, firstout 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 a

control period in a prior year or the control period in the year of 
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the excess emissions or 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 the 

owners and operators of a group of one or more TR NOX Ozone Season

sources and units in a State (and Indian country within the borders 

of such State) only if the TR NOX Ozone Season allowances: 

(1) Were allocated for a control period in a prior year or the 

control period in the given year or in the immediately following 

year; and

(2) Are held in the assurance account, established by the 

Administrator for such owners and operators of such group of TR NOX

Ozone Season sources and units in such State (and Indian country 

within the borders of such State) under paragraph (b)(3) of this 

section, as of the deadline established in paragraph (b)(4) of this 

section. 
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(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 June 1, 2013 and June 1 of each year thereafter, the 

Administrator will:

(i) Calculate, for each State (and Indian country within the borders 

of such State), the total NOX emissions from all TR NOX Ozone Season

units at TR NOX Ozone Season sources in the State (and Indian country 

within the borders of such State) during the control period in the 

year before the year of this calculation deadline and the amount, if 

any, by which such total NOX emissions exceed the State assurance 

level as described in §97.506(c)(2)(iii); and

(ii) Promulgate a notice of data availability of the results of the 

calculations required in paragraph (b)(1)(i) of this section,

including separate calculations of the NOX emissions from each TR NOX

Ozone Season source. 

(2) For each notice of data availability required in paragraph 

(b)(1)(ii) of this section and for any State (and Indian country 

within the borders of such State) identified in such notice as having 

TR NOX Ozone Season units with total NOX emissions exceeding the State 
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assurance level for a control period in a given year, as described in 

§97.506(c)(2)(iii):

(i) By July 1 immediately after the promulgation of such notice, the 

designated representative of each TR NOX Ozone Season source in each 

such State (and Indian country within the borders of such State) 

shall submit a statement, in a format prescribed by the 

Administrator, providing for each TR NOX Ozone Season unit (if any) at 

the source that operates during, but is not allocated an amount of TR 

NOX Ozone Season allowances for, such control period, the unit’s 

allowable NOX emission rate for such control period and, if such rate 

is expressed in lb per mmBtu, the unit’s heat rate. 

(ii) By August 1 immediately after the promulgation of such notice, 

the Administrator will calculate, for each such State (and Indian 

country within the borders of such State) and such control period and 

each common designated representative for such control period for a 

group of one or more TR NOX Ozone Season sources and units in the 

State (and Indian country within the borders of such State), the 

common designated representative’s share of the total NOX emissions 

from all TR NOX Ozone Season units at TR NOX Ozone Season sources in 

the State (and Indian country within the borders of such State), the 

common designated representative’s assurance level, and the amount 

(if any) of TR NOX Ozone Season allowances that the owners and 

operators of such group of sources and units must hold in accordance 
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with the calculation formula in §97.506(c)(2)(i) and will promulgate 

a notice of data 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)(2)(ii) of this section and the 

calculations referenced by the relevant notice of data availability 

required in paragraph (b)(1)(i) of this section.

(A) Objections shall be submitted by the deadline specified in such 

notice and shall be limited to addressing whether the calculations 

referenced in the relevant notice required under paragraph (b)(1)(ii) 

of this section and referenced in the notice required under paragraph 

(b)(2)(ii) of this section are in accordance with §97.506(c)(2)(iii),

§§97.506(b) and 97.530 through 97.535, the definitions of “common 

designated representative”, “common designated representative’s

assurance level”, and “common designated representative’s share” in 

§97.502, and the calculation formula in §97.506(c)(2)(i).

(B) 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)(iii)(A) of this section. By October 1

immediately after the promulgation of such notice, the Administrator 

will promulgate a notice of data availability of any adjustments that 

the Administrator determines to be necessary and the reasons for 
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accepting or rejecting any objections submitted in accordance with 

paragraph (b)(2)(iii)(A) of this section.

(3) For any State (and Indian country within the borders of such 

State) referenced in each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section as having TR NOX Ozone Season

units with total NOX emissions exceeding the State assurance level for 

a control period in a given year, the Administrator will establish 

one assurance account for each set of owners and operators 

referenced, in the notice of data availability required under 

paragraph (b)(2)(iii)(B) of this section, as all of the owners and 

operators of a group of TR NOX Ozone Season sources and units in the 

State (and Indian country within the borders of such State) having a 

common designated representative for such control period and as being 

required to hold TR NOX Ozone Season allowances. 

(4)(i) As of midnight of November 1 immediately after the 

promulgation of each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section, the owners and operators

described in paragraph (b)(3) of this section shall hold in the 

assurance account established for the them and for the appropriate TR 

NOX Ozone Season sources, TR NOX Ozone Season units, and State (and 

Indian country within the borders of such State) under paragraph 

(b)(3) of this section a total amount of TR NOX Ozone Season

allowances, available for deduction under paragraph (a) of this 

section, equal to the amount such owners and operators are required 
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to hold with regard to such sources, units and State (and Indian 

country within the borders of such State) as calculated by the 

Administrator and referenced in such notice. 

(ii) Notwithstanding the allowance-holding deadline specified in 

paragraph (b)(4)(i) of this section, if November 1 is not a business 

day, then such allowance-holding deadline shall be midnight of the 

first business day thereafter.

(5) After November 1 (or the date described in paragraph (b)(4)(ii) 

of this section) immediately after the promulgation of each notice of 

data availability required in paragraph (b)(2)(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 determine whether the owners and 

operators described in paragraph (b)(3) of this section hold, in the 

assurance account for the appropriate TR NOX Ozone Season sources, TR 

NOX Ozone Season units, and State (and Indian country within the 

borders of such State) established under paragraph (b)(3) of this 

section, the amount of TR NOX Ozone Season allowances available under 

paragraph (a) of this section that the owners and operators are

required to hold with regard to such sources, units, and State (and 

Indian country within the borders of such State) as calculated by the 

Administrator and referenced in the notice required in paragraph 

(b)(2)(iii)(B) of this section.
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(6) Notwithstanding any other provision of this subpart and any 

revision, made by or submitted to the Administrator after the 

promulgation of the notice of data availability required in paragraph 

(b)(2)(iii)(B) of this section for a control period in a given year, 

of any data used in making the calculations referenced in such 

notice, the amounts of TR NOX Ozone Season allowances that the owners 

and operators are required to hold in accordance with 

§97.506(c)(2)(i) for such control period shall continue to be such 

amounts as calculated by the Administrator and referenced in such 

notice required in paragraph (b)(2)(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 and operators 

are required to hold in accordance with the calculation formula in 

§97.506(c)(2)(i) for such control period with regard to the TR NOX

Ozone Season sources, TR NOX Ozone Season units, and State (and Indian 

country within the borders of such State) involved, provided that 

such litigation under part 78 of this chapter, or the proceeding 

under part 78 of this chapter that resulted in the decision appealed 
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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)(iii)(B) of this section.

(ii) If any such data are revised by the owners and operators of a TR 

NOX Ozone Season source and TR NOX Ozone Season unit whose designated 

representative submitted such data under paragraph (b)(2)(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 and operators are required to hold in 

accordance with the calculation formula in §97.506(c)(2)(i) for such

control period with regard to the TR NOX Ozone Season sources, TR NOX

Ozone Season units, and State (and Indian country within the borders 

of such State) involved, provided that such litigation was initiated 

no later than 30 days after promulgation of such notice required in 

paragraph (b)(2)(iii)(B) of this section.

(iii) If the revised data are used to recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this section, the amount of TR NOX

Ozone Season allowances that the owners and operators are required to 

hold for such control period with regard to the TR NOX Ozone Season

sources, TR NOX Ozone Season units, and State (and Indian country 

within the borders of such State) involved—
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(A) Where the amount of TR NOX Ozone Season allowances that the owners 

and operators are 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 owners and operators shall hold the 

additional amount of TR NOX Ozone Season allowances in the assurance

account established by the Administrator for the appropriate TR NOX

Ozone Season sources, TR NOX Ozone Season units, and State (and Indian 

country within the borders of such State) under paragraph (b)(3) of 

this section. The owners’ and operators’ failure to hold such 

additional amount, as required, before the new deadline shall not be 

a violation of the Clean Air Act. The owners’ and operators’ 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 owners and operators fail to hold as required as 

of the new deadline, and each day in such control period, shall be a 

separate violation of the Clean Air Act. 

(B) For the owners and operators 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 all

accounts from which TR NOX Ozone Season allowances were transferred by 

such owners and operators for such control period to the assurance 

account established by the Administrator for the appropriate at TR NOX

Ozone Season sources, TR NOX Ozone Season units, and State (and Indian 

country within the borders of such State) under paragraph (b)(3) of 
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this section, a total amount of the TR NOX Ozone Season allowances 

held in such assurance account equal to the amount of the decrease. 

If TR NOX Ozone Season allowances were transferred to such assurance 

account from more than one account, the amount of TR NOX Ozone Season

allowances recorded in each such transferor account will be in 

proportion to the percentage of the total amount of TR NOX Ozone 

Season allowances transferred to such assurance account for such 

control period from such transferor account. 

(C) Each TR NOX Ozone Season allowance held under paragraph 

(b)(6)(iii)(A) of this section as a result of recalculation of 

requirements under the TR NOX Ozone Season assurance provisions for 

such control period must be a TR NOX Ozone Season allowance allocated 

for a control period in a year before or the year immediately 

following, or in the same year as, the year of such control period. 

§ 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, or 97.528.
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§ 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 compliance account or 

an assurance 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 
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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 
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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 Ozone Season unit that commences 

commercial operation before July 1, 2011, 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:

(i) 180 calendar days 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 
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period basis under §97.534(d)(2)(ii), by the following date:

(i) 180 calendar days 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) 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), (2), or (3) of this section shall meet the 

requirements of §§75.4(e)(1) through (e)(4) of this chapter, except 

that:

(i) Such requirements shall apply to the monitoring systems required 

under §97.530 through §97.535, rather than the monitoring systems 

required under part 75 of this chapter;

(ii) NOX emission rate, NOX concentration, stack gas moisture content, 

stack gas volumetric flow rate, and O2 or CO2 concentration data shall 

be determined and reported, rather than the data listed in 

§75.4(e)(2) of this chapter; and
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(iii) Any petition for another procedure under §75.4(e)(2) of this 

chapter shall be submitted under §97.535, rather than §75.66.

(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 to the 

atmosphere without accounting for all such NOX in accordance with the 
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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 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 
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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.
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(b) The recertification provisions of this section shall apply to a 

monitoring system under §97.530(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 §97.535 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.
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(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.

(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 

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) 
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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, 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.
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(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 
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(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. 

(C) Disapproval notice. If the certification application shows that 

any monitoring system does not meet the performance requirements of 
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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 
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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 
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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 
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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 State or permitting authority. By issuing the notice of 

disapproval, the Administrator revokes prospectively the 

certification status of the monitoring system. The data measured and 
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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 paragraphs (b) 

through (e) of 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. 
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(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; or

(ii) For a unit that commences commercial operation on or after July 

1, 2011, the calendar quarter corresponding to the earlier of the 
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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, 
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2012; or

(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) 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.

(4) 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 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.
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(5) 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.

(6) 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)(3) of this section.
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(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.
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§ 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. 

(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. 
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(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.

76. Part 97 is amended by adding subpart CCCCC to read as follows:

Subpart CCCCC—TR SO2 Group 1 Trading Program 

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 setasides, Indian country 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 to new units.
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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 compliance accounts and general 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.
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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.

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 

§52.39 of this chapter, as a means of mitigating interstate transport 

of fine particulates and sulfur dioxide.
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§ 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 multi-state 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 determined by the Administrator) 

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 1

allowances, the determination by the Administrator, State, or 

permitting authority, in accordance with this subpart and any SIP 

revision submitted by the State and approved by the Administrator 

under §52.39(d) (e), or (f) of this chapter, of the amount of such TR 

SO2 Group 1 allowances to be initially credited, at no cost to the 

recipient, to:

(1) A TR SO2 Group 1 unit;

(2) A new unit set-aside;
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(3) An Indian country new unit set-aside; or

(4) An entity not listed in paragraphs (1) through (3) of this 

definition;

(5) Provided that, if the Administrator, State, or permitting 

authority initially credits, to a TR SO2 Group 1 unit qualifying for 

an initial credit, a credit in the amount of zero TR SO2 Group 1

allowances, the TR SO2 Group 1 unit will be treated as being allocated 

an amount (i.e., zero) of TR SO2 Group 1 allowances. 

Allowable SO2 emission rate means, for a unit, the most stringent 

State or federal SO2 emission rate limit (in lb/MWhr or, if in 

lb/mmBtu, converted to lb/MWhr by multiplying it by the unit’s heat 

rate in mmBtu/MWhr) 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, recorded, held, deducted, or transferred 

only as whole allowances. 

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.
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Allowance transfer deadline means, for a control period in a given 

year, 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 emissions 

limitation for such control period in accordance with §§97.606 and 

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 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 the respective program. 

Assurance account means an Allowance Management System account, 

established by the Administrator under §97.625(b)(3) for certain 

owners and operators of a group of one or more TR SO2 Group 1 sources 

and units in a given State (and Indian country within the borders of 

such State), in which are held TR SO2 Group 1 allowances available for 
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use for a control period in a given year in complying with the TR SO2

Group 1 assurance provisions in accordance with §§97.606 and 97.625. 

Authorized account representative means, for 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, for 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
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(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 pressuretreated, 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.

Business day means a day that does not fall on a weekend or a federal 

holiday.

Certifying official means a natural person who is:
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(1) For a corporation, a president, secretary, treasurer, or vicepresident of 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 “coal” as defined in §72.2 of this chapter.

Coal-derived fuel means any fuel (whether in a solid, liquid, or 

gaseous state) produced by the mechanical, thermal, or chemical 

processing of coal.

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 that is a toppingcycle unit or a bottoming-cycle unit:
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(1) Operating as part of a cogeneration system; and

(2) Producing on an annual average basis—

(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 than 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 requirements in paragraph (2) of this 

definition shall not apply to a calendar year referenced in paragraph 

(2) of this definition during which the unit did not operate at all;

(4) 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
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(5) Provided that, if, throughout its operation during the 12-month 

period or a calendar year referenced in paragraph (2) of this 

definition, a unit is operated as part of a cogeneration system and 

the cogeneration system meets on a system-wide basis the requirement 

in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall 

be deemed to meet such requirement during that 12-month period or 

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 January 1, 2005 or the date the unit commences commercial 
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operation as defined in the introductory text of paragraph (1) of 

this definition and that subsequently undergoes a physical change or 

is moved to a new location or 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 January 1, 2005 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 or a different 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 January 1, 2005 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 
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definition and that subsequently undergoes a physical change or is 

moved to a different location or 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 or 

a different 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.

Common designated representative means, with regard to a control 

period in a given year, a designated representative where, as of 

April 1 immediately after the allowance transfer deadline for such 

control period, the same natural person is authorized under 

§§97.613(a) and 97.615(a) as the designated representative for a 

group of one or more TR SO2 Group 1 sources and units located in a 

State (and Indian country within the borders of such State).

Common designated representative’s assurance level means, with regard 

to a specific common designated representative and a State (and 

Indian country within the borders of such State) and control period 

in a given year for which the State assurance level is exceeded as 
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described in §97.606(c)(2)(iii), the common designated 

representative’s share of the State SO2 Group 1 trading budget with 

the variability limit for the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative for a control period in a 

given year:

(1) With regard to a total amount of SO2 emissions from all TR SO2

Group 1 units in a State (and Indian country within the borders of 

such State) during such control period, the total tonnage of SO2

emissions during such control period from a group of one or more TR 

SO2 Group 1 units located in such State (and such Indian country) and 

having the common designated representative for such control period; 

(2) With regard to a State SO2 Group 1 trading budget with the 

variability limit for such control period, the amount (rounded to the 

nearest allowance) equal to the sum of the total amount of TR SO2

Group 1 allowances allocated for such control period to a group of 

one or more TR SO2 Group 1 units located in the State (and Indian 

country within the borders of such State) and having the common 

designated representative for such control period and of the total 

amount of TR SO2 Group 1 allowances purchased by an owner or operator 

of such TR SO2 Group 1 units in an auction for such control period and 

submitted by the State or the permitting authority to the 

Administrator for recordation in the compliance accounts for such TR 
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SO2 Group 1 units in accordance with the TR SO2 Group 1 allowance 

auction provisions in a SIP revision approved by the Administrator 

under §52.39(e) or (f) of this chapter, multiplied by the sum of the 

State SO2 Group 1 trading budget under §97.610(a) and the State’s 

variability limit under §97.610(b) for such control period and 

divided by such State SO2 Group 1 trading budget; 

(3) Provided that, in the case of a unit that operates during, but 

has no amount of TR SO2 Group 1 allowances allocated under §§97.611 

and 97.612 for, such 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 unit’s allowable SO2 emission rate 

applicable to such control period, multiplied by a capacity factor of 

0.85 (if the unit is a boiler combusting any amount of coal or coalderived fuel during such control period), 0.24 (if the unit is a 

simple combustion turbine during such control period), 0.67 (if the 

unit is a combined cycle turbine during such control period), 0.74

(if the unit is an integrated coal gasification combined cycle unit 

during such control period), or 0.36 (for any other unit), 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. 

Common stack means a single flue through which emissions from 2 or 

more units are exhausted.
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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 to 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 a given year in complying with the source's TR SO2 Group 1

emissions limitation in accordance with §§97.606 and 97.624. 

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 
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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 
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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 the respective program. 

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:

(1) In accordance with this subpart; and

(2) With regard to a period before the unit or source is required to 

measure, record, and report such air pollutants in accordance with 

this subpart, in accordance with part 75 of this chapter.

Excess emissions means any ton of emissions from the TR SO2 Group 1

units at a TR SO2 Group 1 source during a control period in a given 

year that exceeds the TR SO2 Group 1 emissions limitation for the 

source for such control period.

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 the limitation on “average annual fuel 

consumption of fossil fuel” in §§97.604(b)(2)(i)(B) and (ii), natural 
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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 2005 or any calendar year thereafter.

General account means an Allowance Management System account, 

established under this subpart, that is not a compliance account or 

an assurance account.

Generator means a device that produces electricity.

Gross electrical output means, for 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, for a unit for a specified period of time, the 

product (in mmBtu/time) of the gross calorific value of the fuel (in 

mmBtu/lb) fed into the unit multiplied by the fuel feed rate (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.
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Heat input rate means, for a unit, the amount of heat input (in 

mmBtu) divided by unit operating time (in hr) or, for a unit and 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.

Heat rate means, for a unit, the unit’s maximum design heat input (in 

Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the unit’s 

maximum hourly load.

Indian country means “Indian country” as defined in 18 U.S.C. 1151.

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 
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nameplate capacity and associated energy generated by the unit at the 

end of the period.

Maximum design heat input means, for a unit, the maximum amount of 

fuel per hour (in Btu/hr) that the 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, rounded 

to the nearest tenth) 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 

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 (in MWe, rounded to 

the nearest tenth) as of such completion as specified by the person 

conducting the physical change.
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Natural gas means “natural gas” as defined in §72.2 of this chapter.

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, for a TR SO2 Group 1 source or a TR SO2 Group 1 unit 

at a source respectively, any person who operates, controls, or 

supervises a TR SO2 Group 1 unit at the source or the TR SO2 Group 1

unit and shall include, but not be limited to, any holding company, 

utility system, or plant manager of such source or unit.

Owner means, for 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; 

and
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(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-the-unit, firm power 

contractual arrangement. 

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, for a unit, 33 percent of 

the 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, auction, transfer, or 

deduction.
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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) The use of reject heat from electricity production in a useful 

thermal energy application or process; or

(2) 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.
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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 that is subject to the TR SO2 Group 1

Trading Program pursuant to §52.39(a),(b), (d), (e), and (f) 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 
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at least some of the reject heat from the electricity production is 

then used to provide useful thermal energy.

Total energy input means, for a unit, total energy of all forms 

supplied to the 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, for a unit, 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 in accordance with 

subpart AAAAA of this part and §52.38(a) of this chapter (including 

such a program that is revised in a SIP revision approved by the 

Administrator under §52.38(a)(3) or (4) of this chapter or that is 

established in a SIP revision approved by the Administrator under 
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§52.38(a)(5) 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 in 

accordance with subpart BBBBB of this part and §52.38(b) of this 

chapter (including such a program that is revised in a SIP revision 

approved by the Administrator under §52.38(b)(3) or (4) of this 

chapter or that is established in a SIP revision approved by the 

Administrator under §52.38(b)(5) 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 or auctioned by the Administrator under this subpart, or by 

a State or permitting authority under a SIP revision approved by the 

Administrator under §52.39(d), (e), or (f) of this chapter, to emit 

one ton of SO2 during a control period of the specified calendar year 

for which the authorization is allocated or auctioned 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 from 

an assurance account (e.g., in order to account for compliance with 

the assurance provisions under §§97.606 and 97.625). 
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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 in accordance with 

this subpart and §52.39(a), (b), (d) through (f), (j), and (k) of 

this chapter (including such a program that is revised in a SIP 

revision approved by the Administrator under §52.39(d) or (e) of this 
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chapter or that is established in a SIP revision approved by the 

Administrator under §52.39(f) 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-fuel-fired boiler, stationary, 

fossil-fuel-fired combustion turbine, or other stationary, fossilfuel-fired combustion device. A unit that undergoes a physical 

change or is moved to a different location or source shall continue 

to be treated as the same unit. A unit (the replaced unit) that is 

replaced by another unit (the replacement unit) at the same or a 

different source shall continue to be treated as the same unit, and 

the replacement unit shall be treated as a separate unit.

Unit operating day means, with regard to a unit, a calendar day in 

which the unit combusts any fuel.

Unit operating hour or hour of unit operation means, with regard to a 

unit, an hour in which the unit combusts any fuel.

Useful power means, with regard to a unit, electricity or mechanical 

energy that the 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).
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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
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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 (and Indian country within the 

borders of such 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, fossilfuel-fired boiler or stationary, fossil-fuel-fired combustion turbine 
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serving at any time, on or after January 1, 2005, 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 (and Indian country within the borders of 

such 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) or (2)(i) of this section shall not be a TR SO2

Group 1 unit:

(1)(i) Any unit:

(A) Qualifying as a cogeneration unit throughout the later of 2005 or 

the 12-month period starting on the date the unit first produces 

electricity and continuing to qualify as a cogeneration unit

throughout each calendar year ending after the later of 2005 or such 

12-month period; and
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(B) Not supplying in 2005 or any calendar year thereafter 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, after qualifying under paragraph (b)(1)(i) of this section 

as not being a TR SO2 Group 1 unit, a unit subsequently no longer 

meets all the requirements of paragraph (b)(1)(i) of this section, 

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. The unit 

shall thereafter continue to be a TR SO2 Group 1 unit. 

(2)(i) Any unit:

(A) Qualifying as a solid waste incineration unit throughout the 

later of 2005 or the 12-month period starting on the date the unit 

first produces electricity and continuing to qualify as a solid waste 

incineration unit throughout each calendar year ending after the 

later of 2005 or such 12-month period; and

(B) With an average annual fuel consumption of fossil fuel for the 

first 3 consecutive calendar years of operation starting no earlier 

than 2005 of less than 20 percent (on a Btu basis) and an average 
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annual fuel consumption of fossil fuel for any 3 consecutive calendar 

years thereafter of less than 20 percent (on a Btu basis).

(ii) If, after qualifying under paragraph (b)(2)(i) of this section 

as not being a TR SO2 Group 1 unit, a unit subsequently no longer 

meets all the requirements of paragraph (b)(1)(i) of this section, 

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 2005 for which the 

unit has an average annual fuel consumption of fossil fuel of 20 

percent or more. The unit shall thereafter continue to be a TR SO2

Group 1 unit.

(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 or a SIP revision approved under §52.39(e) or (f) of this 

chapter, 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 
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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 State or 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.
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(a)(1) Any TR SO2 Group 1 unit that is permanently retired 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.
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(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.
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(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 a control 

period in a given year, 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 total SO2 emissions during a control period in a given year 

from the TR SO2 Group 1 units at a TR SO2 Group 1 source are in excess 

of the TR SO2 Group 1 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 SO2 Group 1

unit at the source shall hold the TR SO2 Group 1 allowances required 

for deduction under §97.624(d); and

(B) The owners and operators of the source and each TR SO2 Group 1

unit at the source shall pay any fine, penalty, or assessment or 

comply with any other remedy imposed, for the same violations, under 

the Clean Air Act, and 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 total SO2 emissions 

during a control period in a given year from all TR SO2 Group 1 units 

at TR SO2 Group 1 sources in a State (and Indian country within the 

borders of such State) exceed the State assurance level, then the 

owners and operators of such sources and units in each group of one 

or more sources and units having a common designated representative 

for such control period, where the common designated representative’s 

share of such SO2 emissions during such control period exceeds the 

common designated representative’s assurance level for the State and 

such control period, shall hold (in the assurance account established 

for the owners and operators of such group) TR SO2 Group 1 allowances 

available for deduction for such control period under §97.625(a) in 

an amount equal to two times the product (rounded to the nearest 

whole number), as determined by the Administrator in accordance with 

§97.625(b), of multiplying—
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(A) The quotient of the amount by which the common designated 

representative’s share of such SO2 emissions exceeds the common 

designated representative’s assurance level divided by the sum of the 

amounts, determined for all common designated representatives for 

such sources and units in the State (and Indian country within the 

borders of such State) for such control period, by which each common 

designated representative’s share of such SO2 emissions exceeds the 

respective common designated representative’s assurance level; and

(B) The amount by which total SO2 emissions from all TR SO2 Group 1

units at TR SO2 Group 1 sources in the State (and Indian country 

within the borders of such State) for such control period exceed the 

State assurance level. 

(ii) The owners and operators 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) Total SO2 emissions from all TR SO2 Group 1 units at TR SO2

Group 1 sources in a State (and Indian country within the borders of 

such State) during a control period in a given year exceed the State 

assurance level if such total SO2 emissions exceed the sum, for such 

control period, of the State SO2 Group 1 trading budget under 

§97.610(a) and the State’s variability limit under §97.610(b).
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(iv) It shall not be a violation of this subpart or of the Clean Air 

Act if total SO2 emissions from all TR SO2 Group 1 units at TR SO2

Group 1 sources in a State (and Indian country within the borders of 

such State) during a control period exceed the State assurance level 

or if a common designated representative’s share of total SO2

emissions from the TR SO2 Group 1 units at TR SO2 Group 1 sources in a 

State (and Indian country within the borders of such State) during a 

control period exceeds the common designated representative’s 

assurance level. 

(v) To the extent the owners and operators fail to hold TR SO2 Group 1

allowances for a control period in a given year in accordance with 

paragraphs (c)(2)(i) through (iii) of this section, 

(A) The owners and operators 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 owners and operators fail 

to hold for such control period in accordance with paragraphs 

(c)(2)(i) through (iii) 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 under paragraphs (c)(1) and (c)(2) of this section for 
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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.

(4) Vintage of allowances held for compliance. (i) A TR SO2 Group 1

allowance held for compliance with the requirements under paragraph 

(c)(1)(i) of this section for a control period in a given year must 

be a TR SO2 Group 1 allowance that was allocated for such control 

period or a control period in a prior year.

(ii) A TR SO2 Group 1 allowance held for compliance with the 

requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through (iii)

of this section for a control period in a given year must be a TR SO2

Group 1 allowance that was allocated for a control period in a prior 

year or the control period in the given year or in the immediately 

following year.

(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. A TR SO2 Group 1 allowance is a limited 

authorization to emit one ton of SO2 during the control period in one 

year. Such authorization is limited in its use and duration as 

follows:
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(i) Such authorization shall only be used in accordance with the TR 

SO2 Group 1 Trading Program; and 

(ii) Notwithstanding any other provision of this subpart, the 

Administrator has the authority to terminate or limit the use and 

duration of 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 

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 §§97.630 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 
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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 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 certificate of representation 

and documents are superseded because of the submission of a new 

certificate of representation under §97.616 changing the designated 

representative.
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(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.

(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, except as provided in §97.618. 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 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.
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(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, is not a business day, 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.
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§ 97.609 [Reserved]

§ 97.610 State SO2 Group 1 trading budgets, new unit set-asides, 

Indian country new unit set-aside, and variability limits.

(a) The State SO2 Group 1 trading budgets, new unit set-asides, and 

Indian country 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)*

for 2012 and 2013

New unit setaside (tons)

for 2012 and 

2013

Indian country new 

unit set-aside 

(tons)

for 2012 and 2013

Illinois 234,889 11,744 ---

Indiana 285,424 8,563 ---

Iowa 107,085 2,035 107

Kentucky 232,662 13,960 ---

Maryland 30,120 602 ---

Michigan 229,303 4,357 229

Missouri 207,466 4,149 ---

New Jersey 5,574 111 ---

New York 27,325 520 27

North Carolina 136,881 10,813 137

Ohio 310,230 6,205 ---

Pennsylvania 278,651 5,573 ---

Tennessee 148,150 2,963 ---

Virginia 70,820 2,833 ---

West Virginia 146,174 10,232 ---

Wisconsin 79,480 3,894 80

State SO2 Group 1 trading New unit set- Indian country 
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budget (tons)*

for 2014 and 

thereafter

aside (tons)

for 2014 and 

thereafter

new unit setaside (tons)

for 2014 and 

thereafter

Illinois 124,123 6,206 ---

Indiana 161,111 4,833 ---

Iowa 75,184 1,429 75

Kentucky 106,284 6,377 ---

Maryland 28,203 564 ---

Michigan 143,995 2,736 144

Missouri 165,941 3,319 ---

New Jersey 5,574 111 ---

New York 18,585 353 19

North Carolina 57,620 4,552 58

Ohio 137,077 2,742 ---

Pennsylvania 112,021 2,240 ---

Tennessee 58,833 1,177 ---

Virginia 35,057 1,402 ---

West Virginia 75,668 5,297 ---

Wisconsin 40,126 1,966 40

* Each trading budget includes the new unit set-aside and, where 

applicable, the Indian country new unit set-aside and does not 

include the variability limit.

(b) The States’ variability limits for the State SO2 Group 1 trading 

budgets for the control periods in 2012 and thereafter are as 

follows:

State

Variability limits

for 2012 and 2013

Variability limits

for 2014 and thereafter

Illinois 42,280 22,342

Indiana 51,376 29,000

Iowa 19,275 13,533

Kentucky 41,879 19,131
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Maryland 5,422 5,077

Michigan 41,275 25,919

Missouri 37,344 29,869

New Jersey 1,003 1,003

New York 4,919 3,345

North Carolina 24,639 10,372

Ohio 55,841 24,674

Pennsylvania 50,157 20,164

Tennessee 26,667 10,590

Virginia 12,748 6,310

West Virginia 26,311 13,620

Wisconsin 14,306 7,223

§ 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 provided in 

a notice of data availability issued by the Administrator. Providing 

an allocation to a unit in such notice does not constitute a 

determination that the unit is a TR SO2 Group 1 unit, and not 

providing an allocation to a unit in such notice 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 

provided an allocation in the notice of data availability issued 

under paragraph (a)(1) of this section does not operate, starting 

after 2011, during the control period in two consecutive years, such 

unit will not be allocated the TR SO2 Group 1 allowances provided in 
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such notice for the unit for the control periods in the fifth year 

after the first such year and in each year after that fifth 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 

State where such unit is located and 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) New unit set-asides. (i) By June 1, 2012 and 

June 1 of each year thereafter, the Administrator will calculate the 

TR SO2 Group 1 allowance allocation to each TR SO2 Group 1 unit in a 

State, in accordance with §97.612(a)(2) through (7) and (12), for the 

control period in the year of the applicable calculation deadline 

under this paragraph and will promulgate a notice of data 

availability of the results of the calculations.

(ii) For each notice of data availability required in paragraph 

(b)(1)(i) of this section, the Administrator will provide an 

opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR SO2 Group 1 units) are in 
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accordance with §97.612(a)(2) through (7) and (12) and §§97.606(b)(2) 

and 97.630 through 97.635. 

(B) The Administrator will adjust the calculations to the extent 

necessary to ensure that they are in accordance with the provisions 

referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(1)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.612(a)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) of this section. 

(iii) If the new unit set-aside for such control period contains any 

TR SO2 Group 1 allowances that have not been allocated in the 

applicable notice of data availability required in paragraph 

(b)(1)(ii) of this section, the Administrator will promulgate, by 

December 15 immediately after such notice, a notice of data 

availability that identifies any TR SO2 Group 1 units that commenced 

commercial operation during the period starting January 1 of the year 

before the year of such control period and ending November 30 of year 

of such control period.

(iv) For each notice of data availability required in paragraph 

(b)(1)(iii) of this section, the Administrator will provide an 
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opportunity for submission of objections to the identification of TR 

SO2 annual units in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR SO2 annual units in such notice is in accordance with paragraph 

(b)(1)(iii) of this section. 

(B) The Administrator will adjust the identification of TR SO2 Group 1

units in the each notice of data availability required in paragraph 

(b)(1)(iii) of this section to the extent necessary to ensure that it 

is in accordance with paragraph (b)(1)(iii) of this section and will 

calculate the TR SO2 Group 1 allowance allocation to each TR SO2 Group 

1 unit in accordance with §97.612(a)(9), (10), and (12) and 

§§97.606(b)(2) and 97.630 through 97.635. By February 15 immediately 

after the promulgation of each notice of data availability required 

in paragraph (b)(1)(iii) of this section, the Administrator will 

promulgate a notice of data availability of any adjustments of the 

identification of TR SO2 Group 1 units that the Administrator 

determines to be necessary, the reasons for accepting or rejecting 

any objections submitted in accordance with paragraph (b)(1)(iv)(A) 

of this section, and the results of such calculations.

(v) To the extent any TR SO2 Group 1 allowances are added to the new 

unit set-aside after promulgation of each notice of data availability 
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required in paragraph (b)(1)(iv) of this section, the Administrator 

will promulgate additional notices of data availability, as deemed 

appropriate, of the allocation of such TR SO2 Group 1 allowances in 

accordance with §97.612(a)(10). 

(2) Indian country new unit set-asides. (i) By June 1, 2012 and June 

1 of each year thereafter, the Administrator will calculate the TR SO2

Group 1 allowance allocation to each TR SO2 Group 1 unit in Indian 

country within the borders of a State, in accordance with 

§97.612(b)(2) through (7) and (12), for the control period in the 

year of the applicable calculation deadline under this paragraph and 

will promulgate a notice of data availability of the results of the 

calculations.

(ii) For each notice of data availability required in paragraph 

(b)(2)(i) of this section, the Administrator will provide an 

opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR SO2 Group 1 units) are in 

accordance with §97.612(b)(2) through (7) and (12) and §§97.606(b)(2) 

and 97.630 through 97.635. 
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(B) 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)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.612(b)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) of this section. 

(iii) If the Indian country new unit set-aside for such control 

period contains any TR SO2 Group 1 allowances that have not been 

allocated in the applicable notice of data availability required in 

paragraph (b)(2)(ii) of this section, the Administrator will 

promulgate, by December 15 immediately after such notice, a notice of 

data availability that identifies any TR SO2 Group 1 units that 

commenced commercial operation during the period starting January 1 

of the year before the year of such control period and ending 

November 30 of year of such control period.

(iv) For each notice of data availability required in paragraph 

(b)(2)(iii) of this section, the Administrator will provide an 

opportunity for submission of objections to the identification of TR 

SO2 annual units in such notice. 
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(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR SO2 annual units in such notice is in accordance with paragraph 

(b)(2)(iii) of this section. 

(B) The Administrator will adjust the identification of TR SO2 Group 1

units in the each notice of data availability required in paragraph 

(b)(2)(iii) of this section to the extent necessary to ensure that it 

is in accordance with paragraph (b)(2)(iii) of this section and will 

calculate the TR SO2 Group 1 allowance allocation to each TR SO2 Group 

1 unit in accordance with §97.612(b)(9), (10), and (12) and 

§§97.606(b)(2) and 97.630 through 97.635. By February 15 immediately 

after the promulgation of each notice of data availability required 

in paragraph (b)(2)(iii) of this section, the Administrator will 

promulgate a notice of data availability of any adjustments of the 

identification of TR SO2 Group 1 units that the Administrator 

determines to be necessary, the reasons for accepting or rejecting 

any objections submitted in accordance with paragraph (b)(2)(iv)(A) 

of this section, and the results of such calculations. 

(v) To the extent any TR SO2 Group 1 allowances are added to the 

Indian country new unit set-aside after promulgation of each notice 

of data availability required in paragraph (b)(2)(iv) of this 

section, the Administrator will promulgate additional notices of data 
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availability, as deemed appropriate, of the allocation of such TR NOX

Annual allowances in accordance with §97.612(b)(10). 

(c) Units incorrectly allocated TR SO2 Group 1 allowances. (1) 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, or under a provision of a SIP revision 

approved under §52.39(d), (e), or (f) of this chapter, where such 

control period and the recipient are covered by the provisions of 

paragraph (c)(1)(i) of this section or were allocated under 

§97.612(a)(2) through (7), (9), and (12) and (b)(2) through (7), (9), 

and (12), or under a provision of a SIP revision approved under 

§52.39(e) or (f) of this chapter, where such control period and the 

recipient are covered by the provisions of paragraph (c)(1)(ii) of 

this section, then the Administrator will notify the designated 

representative of the recipient and will act in accordance with the 

procedures set forth in paragraphs (c)(2) through (5) of this 

section:

(i)(A) The recipient is not actually a TR SO2 Group 1 unit under 

§97.604 as of January 1, 2012 and is allocated TR SO2 Group 1

allowances for such control period or, in the case of an allocation 

under a provision of a SIP revision approved under §52.39(d), (e), or 

(f) of this chapter, the recipient is not actually a TR SO2 Group 1

unit as of January 1, 2012 and is allocated TR SO2 Group 1 allowances 

for such control period that the SIP revision provides should be 
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allocated only to recipients that are TR SO2 Group 1 units as of 

January 1, 2012; or

(B) The recipient is not located as of January 1 of the control 

period in the State from whose SO2 Group 1 trading budget the TR SO2

Group 1 allowances allocated under paragraph (a) of this section, or 

under a provision of a SIP revision approved under §52.39(d), (e), or 

(f) of this chapter, were allocated for such control period. 

(ii) The recipient is not actually a TR SO2 Group 1 unit under §97.604 

as of January 1 of such control period and is allocated TR SO2 Group 1

allowances for such control period or, in the case of an allocation 

under a provision of a SIP revision approved under §52.39(d), (e), or 

(f) of this chapter, the recipient is not actually a TR SO2 Group 1

unit as of January 1 of such control period and is allocated TR SO2

Group 1 allowances for such control period that the SIP revision 

provides should be allocated only to recipients that are TR SO2 Group 

1 units as of January 1 of such control period. 

(2) Except as provided in paragraph (c)(3) or (4) of this section, 

the Administrator will not record such TR SO2 Group 1 allowances under 

§97.621.

(3) If the Administrator already recorded such TR SO2 Group 1

allowances under §97.621 and if the Administrator makes the 

determination under paragraph (c)(1) of this section before making 
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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.

(4) If the Administrator already recorded such TR SO2 Group 1

allowances under §97.621 and if the Administrator makes the 

determination under paragraph (c)(1) of this section 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. 

(5)(i) With regard to the TR SO2 Group 1 allowances that are not 

recorded, or that are deducted as an incorrect allocation, in 

accordance with paragraphs (c)(2) and (3) of this section for a 

recipient under paragraph (c)(1)(i) of this section, the 

Administrator will:

(A) Transfer such TR SO2 Group 1 allowances to the new unit set-aside 

for such control period for the State from whose SO2 Group 1 trading 

budget the TR SO2 Group 1 allowances were allocated; or
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(B) If the State has a SIP revision approved under §52.39(e) or (f) 

covering such control period, include such TR SO2 Group 1 allowances 

in the portion of the State SO2 Group 1 trading budget that may be 

allocated for such control period in accordance with such SIP 

revision. 

(ii) With regard to the TR SO2 Group 1 allowances that were not 

allocated from the Indian country new unit set-aside for such control 

period and that are not recorded, or that are deducted as an 

incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 

this section for a recipient under paragraph (c)(1)(ii) of this 

paragraph, the Administrator will:

(A) Transfer such TR SO2 Group 1 allowances to the new unit set-aside 

for such control period; or

(B) If the State has a SIP revision approved under §52.39(e) or (f) 

covering such control period, include such TR SO2 Group 1 allowances 

in the portion of the State SO2 Group 1 trading budget that may be 

allocated for such control period in accordance with such SIP 

revision. 

(iii) With regard to the TR SO2 Group 1 allowances that were allocated 

from the Indian country new unit set-aside for such control period 

and that are not recorded, or that are deducted as an incorrect 

allocation, in accordance with paragraphs (c)(2) and (3) of this 
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section for a recipient under paragraph (c)(1)(ii) of this paragraph, 

the Administrator will transfer such TR SO2 Group 1 allowances to the 

Indian country new unit set-aside for such control period.

§ 97.612 TR SO2 Group 1 allowance allocations to new units.

(a) For each control period in 2012 and thereafter and for the TR SO2

Group 1 units in each State, the Administrator will allocate TR SO2

Group 1 allowances to the TR SO2 Group 1 units as follows: 

(1) The TR SO2 Group 1 allowances will be allocated to the following 

TR SO2 Group 1 units, except as provided in paragraph (a)(10) of this 

section:

(i) TR SO2 Group 1 units that are not allocated an amount of TR SO2

Group 1 allowances in the notice of data availability issued under 

§97.611(a)(1); 

(ii) TR SO2 Group 1 units whose allocation of an amount of TR SO2

Group 1 allowances for such control period in the notice of data 

availability issued under §97.611(a)(1) is covered by §97.611(c)(2) 

or (3);

(iii) TR SO2 Group 1 units that are allocated an amount of TR SO2

Group 1 allowances for such control period in the notice of data 

availability issued under §97.611(a)(1), which allocation is 

terminated for such control period pursuant to §97.611(a)(2), and 
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that operate during the control period immediately preceding such 

control period; or

(iv) For purposes of paragraph (a)(9) of this section, TR SO2 Group 1

units under §97.611(c)(1)(ii) whose allocation of an amount of TR SO2

Group 1 allowances for such control period in the notice of data 

availability issued under §97.611(b)(1)(ii)(B) is covered by 

§97.611(c)(2) or (3). 

(2) The Administrator will establish a separate new unit set-aside 

for the State for each such control period. Each such new unit setaside 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) and will be allocated additional TR SO2 Group 1 allowances 

(if any) in accordance with §§97.611(a)(2) and (c)(5) and paragraph 

(b)(10) of this section.

(3) The Administrator will determine, for each TR SO2 Group 1 unit 

described in paragraph (a)(1) of this section, an allocation of TR SO2

Group 1 allowances for the later of the following control periods and 

for each subsequent control period:

(i) The control period in 2012;

(ii) The first control period after the control period in which the 

TR SO2 Group 1 unit commences commercial operation; 
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(iii) For a unit described in paragraph (a)(1)(ii) of this section, 

the first control period in which the TR SO2 Group 1 unit operates in 

the State after operating in another jurisdiction and for which the 

unit is not already allocated one or more TR SO2 Group 1 allowances; 

and

(iv) For a unit described in paragraph (a)(1)(iii) of this section, 

the first control period after the control period in which the unit 

resumes operation. 

(4)(i) The allocation to each TR SO2 annual unit described in 

paragraph (a)(1)(i) through (iii) of this section and for each 

control period described in paragraph (a)(3) of this section will be 

an amount equal to the unit’s total tons of SO2 emissions during the 

immediately preceding control period.

(ii) The Administrator will adjust the allocation amount in paragraph 

(a)(4)(i) in accordance with paragraphs (a)(5) through (7) and (12)

of this section.

(5) The Administrator will calculate the sum of the TR SO2 Group 1

allowances determined for all such TR SO2 Group 1 units under 

paragraph (a)(4)(i) of this section in the State for such control 

period.

(6) If the amount of TR SO2 Group 1 allowances in the new unit setaside for the State for such control period is greater than or equal 
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to the sum under paragraph (a)(5) of this section, then the 

Administrator will allocate the amount of TR SO2 Group 1 allowances 

determined for each such TR SO2 Group 1 unit under paragraph (a)(4)(i) 

of this section.

(7) If the amount of TR SO2 Group 1 allowances in the new unit setaside for the State for such control period is less than the sum 

under paragraph (a)(5) of this section, then the Administrator will 

allocate to each such TR SO2 Group 1 unit the amount of the TR SO2

Group 1 allowances determined under paragraph (a)(4)(i) of this 

section for the unit, multiplied by the amount of TR SO2 Group 1

allowances in the new unit set-aside for such control period, divided 

by the sum under paragraph (a)(5) of this section, and rounded to the 

nearest allowance.

(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.611(b)(1)(i) and (ii), of the amount of TR SO2 Group 1 allowances 

allocated under paragraphs (a)(2) through (7) and (12) of this 

section for such control period to each TR SO2 Group 1 unit eligible 

for such allocation.

(9) If, after completion of the procedures under paragraphs (a)(5) 

through (8) of this section for such control period, any unallocated 

TR SO2 Group 1 allowances remain in the new unit set-aside for the 
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State for such control period, the Administrator will allocate such 

TR SO2 Group 1 allowances as follows--

(i) The Administrator will determine, for each unit described in 

paragraph (a)(1) of this section that commenced commercial operation 

during the period starting January 1 of the year before the year of 

such control period and ending November 30 of year of such control 

period, the positive difference (if any) between the unit’s emissions 

during such control period and the amount of TR SO2 Group 1 allowances 

referenced in the notice of data availability required under 

§97.611(b)(1)(ii) for the unit for such control period;

(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (a)(9)(i) of this section;

(iii) If the amount of unallocated TR SO2 Group 1 allowances remaining 

in the new unit set-aside for the State for such control period is

greater than or equal to the sum determined under paragraph 

(a)(9)(ii) of this section, then the Administrator will allocate the 

amount of TR SO2 Group 1 allowances determined for each such TR SO2

Group 1 unit under paragraph (a)(9)(i) of this section; and

(iv) If the amount of unallocated TR SO2 Group 1 allowances remaining 

in the new unit set-aside for the State for such control period is 

less than the sum under paragraph (a)(9)(ii) of this section, then 

the Administrator will allocate to each such TR SO2 Group 1 unit the 
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amount of the TR SO2 Group 1 allowances determined under paragraph 

(a)(9)(i) of this section for the unit, multiplied by the amount of 

unallocated TR SO2 Group 1 allowances remaining in the new unit setaside for such control period, divided by the sum under paragraph 

(a)(9)(ii) of this section, and rounded to the nearest allowance.

(10) If, after completion of the procedures under paragraphs (a)(9)

and (12) of this section for such control period, any unallocated TR 

SO2 Group 1 allowances remain in the new unit set-aside for the State 

for such control period, the Administrator will allocate to each TR 

SO2 Group 1 unit that is in the State, is allocated an amount of TR 

SO2 Group 1 allowances in the notice of data availability issued under 

§97.611(a)(1), 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 sum 

of the amounts of tons in such new unit set-aside and the Indian 

country new unit set-aside for the State for such control period, and 

rounded to the nearest allowance.

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.611(b)(1)(iii), (iv), and (v), of the amount of TR SO2 Group 1
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allowances allocated under paragraphs (a)(9), (10), and (12) of this 

section for such control period to each TR SO2 Group 1 unit eligible 

for such allocation.

(12)(i) Notwithstanding the requirements of paragraphs (a)(2) through 

(11) of this section, if the calculations of allocations of a new 

unit set-aside for a control period in a given year under paragraph 

(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this 

section, or paragraphs (a)(6), (9)(iii), and (10) of this section 

would otherwise result in total allocations of such new unit setaside exceeding the total amount of such new unit set-aside, then the 

Administrator will adjust the results of the calculations under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 

follows. The Administrator will list the TR SO2 Group 1 units in 

descending order based on the amount of such units’ allocations under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, 

and, in cases of equal allocation amounts, in alphabetical order of 

the relevant source’s name and numerical order of the relevant unit’s 

identification number, and will reduce each unit’s allocation under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, by 

one TR SO2 Group 1 allowance (but not below zero) in the order in 

which the units are listed and will repeat this reduction process as 

necessary, until the total allocations of such new unit set-aside

equal the total amount of such new unit set-aside. 
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(ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 

of this section, if the calculations of allocations of a new unit 

set-aside for a control period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section would otherwise result in 

a total allocations of such new unit set-aside less than the total 

amount of such new unit set-aside, then the Administrator will adjust 

the results of the calculations under paragraph (a)(10) of this 

section, as follows. The Administrator will list the TR SO2 Group 1

units in descending order based on the amount of such units’ 

allocations under paragraph (a)(10) of this section and, in cases of 

equal allocation amounts, in alphabetical order of the relevant 

source’s name and numerical order of the relevant unit’s 

identification number, and will increase each unit’s allocation under 

paragraph (a)(10) of this section by one TR SO2 Group 1 allowance in 

the order in which the units are listed and will repeat this increase 

process as necessary, until the total allocations of such new unit 

set-aside equal the total amount of such new unit set-aside. 

(b) For each control period in 2012 and thereafter and for the TR SO2

Group 1 units located in Indian country within the borders of each 

State, the Administrator will allocate TR SO2 Group 1 allowances to 

the TR SO2 Group 1 units as follows: 

(1) The TR SO2 Group 1 allowances will be allocated to the following 

TR SO2 Group 1 units, except as provided in paragraph (b)(10) of this 

section:
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(i) TR SO2 Group 1 units that are not allocated an amount of TR SO2

Group 1 allowances in the notice of data availability issued under 

§97.611(a)(1); or

(ii) For purposes of paragraph (b)(9) of this section, TR SO2 Group 1

units under §97.611(c)(1)(ii) whose allocation of an amount of TR SO2

Group 1 allowances for such control period in the notice of data 

availability issued under §97.611(b)(2)(ii)(B) is covered by 

§97.611(c)(2) or (3). 

(2) The Administrator will establish a separate Indian country new 

unit set-aside for the State for each such control period. Each such 

Indian country 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) and will be allocated additional 

TR SO2 Group 1 allowances (if any) in accordance with §97.611(c)(5).

(3) The Administrator will determine, for each TR SO2 Group 1 unit 

described in paragraph (b)(1) of this section, an allocation of TR SO2

Group 1 allowances for the later of the following control periods and 

for each subsequent control period:

(i) The control period in 2012; and

(ii) The first control period after the control period in which the 

TR SO2 Group 1 unit commences commercial operation.
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(4)(i) The allocation to each TR SO2 annual unit described in 

paragraph (b)(1)(i) of this section and for each control period 

described in paragraph (b)(3) of this section will be an amount equal 

to the unit’s total tons of SO2 emissions during the immediately 

preceding control period.

(ii) The Administrator will adjust the allocation amount in paragraph 

(b)(4)(i) in accordance with paragraphs (b)(5) through (7) and (12)

of this section. 

(5) The Administrator will calculate the sum of the TR SO2 Group 1

allowances determined for all such TR SO2 Group 1 units under 

paragraph (b)(4)(i) of this section in Indian country within the 

borders of the State for such control period.

(6) If the amount of TR SO2 Group 1 allowances in the Indian country 

new unit set-aside for the State for such control period is greater 

than or equal to the sum under paragraph (b)(5) of this section, then 

the Administrator will allocate the amount of TR SO2 Group 1

allowances determined for each such TR SO2 Group 1 unit under 

paragraph (b)(4)(i) of this section.

(7) If the amount of TR SO2 Group 1 allowances in the Indian country 

new unit set-aside for the State for such control period is less than 

the sum under paragraph (b)(5) of this section, then the 

Administrator will allocate to each such TR SO2 Group 1 unit the 
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amount of the TR SO2 Group 1 allowances determined under paragraph 

(b)(4)(i) of this section for the unit, multiplied by the amount of 

TR SO2 Group 1 allowances in the Indian country new unit set-aside for 

such control period, divided by the sum under paragraph (b)(5) of 

this section, and rounded to the nearest allowance.

(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.611(b)(2)(i) and (ii), of the amount of TR SO2 Group 1 allowances 

allocated under paragraphs (b)(2) through (7) and (12) of this 

section for such control period to each TR SO2 Group 1 unit eligible 

for such allocation.

(9) If, after completion of the procedures under paragraphs (b)(5) 

through (8) of this section for such control period, any unallocated 

TR SO2 Group 1 allowances remain in the Indian country new unit setaside for the State for such control period, the Administrator will 

allocate such TR SO2 Group 1 allowances as follows--

(i) The Administrator will determine, for each unit described in 

paragraph (b)(1) of this section that commenced commercial operation 

during the period starting January 1 of the year before the year of 

such control period and ending November 30 of year of such control 

period, the positive difference (if any) between the unit’s emissions 

during such control period and the amount of TR SO2 Group 1 allowances 
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referenced in the notice of data availability required under 

§97.611(b)(2)(ii) for the unit for such control period;

(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (b)(9)(i) of this section;

(iii) If the amount of unallocated TR SO2 Group 1 allowances remaining 

in the Indian country new unit set-aside for the State for such 

control period is greater than or equal to the sum determined under 

paragraph (b)(9)(ii) of this section, then the Administrator will 

allocate the amount of TR SO2 Group 1 allowances determined for each 

such TR SO2 Group 1 unit under paragraph (b)(9)(i) of this section; 

and

(iv) If the amount of unallocated TR SO2 Group 1 allowances remaining 

in the Indian country new unit set-aside for the State for such 

control period is less than the sum under paragraph (b)(9)(ii) of 

this section, then the Administrator will allocate to each such TR SO2

Group 1 unit the amount of the TR SO2 Group 1 allowances determined 

under paragraph (b)(9)(i) of this section for the unit, multiplied by 

the amount of unallocated TR SO2 Group 1 allowances remaining in the 

Indian country new unit set-aside for such control period, divided by 

the sum under paragraph (b)(9)(ii) of this section, and rounded to 

the nearest allowance.
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(10) If, after completion of the procedures under paragraphs (b)(9)

and (12) of this section for such control period, any unallocated TR 

SO2 Group 1 allowances remain in the Indian country new unit set-aside 

for the State for such control period, the Administrator will:

(i) Transfer such unallocated TR SO2 Group 1 allowances to the new 

unit set-aside for the State for such control period; or 

(ii) If the State has a SIP revision approved under §52.39(d), (e), 

or (f) of this chapter covering such control period, include such 

unallocated TR SO2 Group 1 allowances in the portion of the State SO2

Group 1 trading budget that may be allocated for such control period 

in accordance with such SIP revision. 

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.611(b)(2)(iii), (iv), and (v), of the amount of TR SO2 Group 1

allowances allocated under paragraphs (b)(9), (10), and (12) for such 

control period to each TR SO2 Group 1 unit eligible for such 

allocation.

(12)(i) Notwithstanding the requirements of paragraphs (b)(2) through 

(11) of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 

paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) of 

this section, or paragraphs (b)(6), (9)(iii), and (10) of this 
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section would otherwise result in total allocations of such Indian 

country new unit set-aside exceeding the total amount of such Indian 

country new unit set-aside, then the Administrator will adjust the 

results of the calculations under paragraph (b)(7), (9)(iv), or (10) 

of this section, as applicable, as follows. The Administrator will 

list the TR SO2 Group 1 units in descending order based on the amount 

of such units’ allocations under paragraph (b)(7), (9)(iv), or (10) 

of this section, as applicable, and, in cases of equal allocation 

amounts, in alphabetical order of the relevant source’s name and 

numerical order of the relevant unit’s identification number, and 

will reduce each unit’s allocation under paragraph (b)(7), (9)(iv), 

or (10) of this section, as applicable, by one TR SO2 Group 1

allowance (but not below zero) in the order in which the units are 

listed and will repeat this reduction process as necessary, until the 

total allocations of such Indian country new unit set-aside equal the 

total amount of such Indian country new unit set-aside. 

(ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 

of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 

paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 

result in a total allocations of such Indian country new unit setaside less than the total amount of such Indian country new unit setaside, then the Administrator will adjust the results of the 

calculations under paragraph (b)(10) of this section, as follows. 
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The Administrator will list the TR SO2 Group 1 units in descending 

order based on the amount of such units’ allocations under paragraph 

(b)(10) of this section and, in cases of equal allocation amounts, in 

alphabetical order of the relevant source’s name and numerical order 

of the relevant unit’s identification number, and will increase each 

unit’s allocation under paragraph (b)(10) of this section by one TR 

SO2 Group 1 allowance in the order in which the units are listed and 

will repeat this increase process as necessary, until the total 

allocations of such Indian country new unit set-aside equal the total 

amount of such Indian country new unit set-aside. 

§ 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:
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(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).
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(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, 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” (as distinguished from 

the term “common 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 
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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; changes in units at 

the source.
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(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 at the 

source is not included in the list of owners and operators in the 

certificate of representation under §97.616, such owner or operator 
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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 at the source, 

including the addition or removal of an 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 reflect the 

change.

(d) Changes in units at the source. Within 30 days of any change in 

which units are located at a TR SO2 Group 1 source (including the 

addition or removal of a unit), the designated representative or any 

alternate designated representative shall submit a certificate of 

representation under §97.616 amending the list of units to reflect 

the change. 

(1) If the change is the addition of a unit that operated (other than 

for purposes of testing by the manufacturer before initial 

installation) before being located at the source, then the 

certificate of representation shall identify, in a format prescribed 
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by the Administrator, the entity from whom the unit was purchased or 

otherwise obtained (including name, address, telephone number, and 

facsimile number (if any)), the date on which the unit was purchased 

or otherwise obtained, and the date on which the unit became located 

at the source.

(2) If the change is the removal of a unit, then the certificate of 

representation shall identify, in a format prescribed by the 

Administrator, the entity to which the unit was sold or that 

otherwise obtained the unit (including name, address, telephone 

number, and facsimile number (if any)), the date on which the unit 

was sold or otherwise obtained, and the date on which the unit became 

no longer located at the source. 

§ 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 
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MWe, rounded to the nearest tenth) of each generator served by each 

such unit, actual or projected date of commencement of commercial 

operation, and a statement of whether such source is located in 

Indian Country. If a projected date of commencement of commercial 

operation is provided, the actual date of commencement of commercial 

operation shall be provided when such information becomes available.

(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, 
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inactions, or submissions and by any decision or 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-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 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 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 
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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 paragraph (a) of this section, 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 
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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 a natural person 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;
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(2) The name, address, e-mail address, telephone number, and 

facsimile transmission number (if any) of each such natural person 

(referred to in this section 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 
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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 compliance accounts, assurance accounts, 

and general 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 
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authorized account representative and the alternate authorized 

account representative respectively of the compliance account.

(b) Assurance accounts. The Administrator will establish assurance 

accounts for certain owners and operators and States in accordance 

with §97.625(b)(3). 

(c) 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.
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(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 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 decision or order issued to me 

by the Administrator regarding the general account.”
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(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 
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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 

decision or order issued to the authorized account representative or 

alternate authorized account representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph (c)(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 
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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 (c)(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 
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of a superseding complete application for a general account under 

paragraph (c)(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 or removal of a 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 
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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 (c)(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 (c)(4)(i) 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 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, 
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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 a natural person to make an 

electronic submission to the Administrator in accordance with 

paragraph (c)(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;
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(B) The name, address, e-mail address, telephone number, and 

facsimile transmission number (if any) of each such natural person 

(referred to in this section as an “agent”);

(C) For each such natural person, a list of the type or types of 

electronic submissions under paragraph (c)(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(c)(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(c)(5)(iv), I agree to maintain an email 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(c)(5) is terminated.”.
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(iv) A notice of delegation submitted under paragraph (c)(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 (c)(5)(iii)(D) of this section and made in accordance with 

a notice of delegation effective under paragraph (c)(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) Closing a general account. (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.
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(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 30 days after the notice is sent. The 

account will be closed after the 30-day period unless, before the end 

of the 30-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.

(d) Account identification. The Administrator will assign a unique 

identifying number to each account established under paragraph (a), 

(b), or (c) of this section.

(e) Responsibilities of authorized account representative and 

alternate authorized account representative. After the establishment 

of a compliance account or general 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 (c)(2)(ii) and (c)(5) of this section. 
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§ 97.621 Recordation of TR SO2 Group 1 allowance allocations and 

auction results.

(a) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR SO2 Group 1

source's compliance account the TR SO2 Group 1 allowances allocated to 

the TR SO2 Group 1 units at the source in accordance with §97.611(a) 

for the control period in 2012.

(b) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR SO2 Group 1

source's compliance account the TR SO2 Group 1 allowances allocated to 

the TR SO2 Group 1 units at the source in accordance with §97.611(a) 

for the control period in 2013, unless the State in which the source 

is located notifies the Administrator in writing by [INSERT DATE 70 

DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER] of the State’s 

intent to submit to the Administrator a complete SIP revision by 

April 1, 2012 meeting the requirements of §52.39(d)(1) through (4) of 

this chapter.

(1) If, by April 1, 2012, the State does not submit to the 

Administrator such complete SIP revision, the Administrator will 

record by April 15, 2012 in each TR SO2 Group 1 source's compliance 

account the TR SO2 Group 1 allowances allocated to the TR SO2 Group 1

units at the source in accordance with §97.611(a) for the control 

period in 2013.
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(2) If the State submits to the Administrator by April 1, 2012, and 

the Administrator approves by October 1, 2012, such complete SIP 

revision, the Administrator will record by October 1, 2012 in each TR 

SO2 Group 1 source's compliance account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units at the source as provided in 

such approved, complete SIP revision for the control period in 2013.

(3) If the State submits to the Administrator by April 1, 2012, and 

the Administrator does not approve by October 1, 2012, such complete 

SIP revision, the Administrator will record by October 1, 2012 in 

each TR SO2 Group 1 source's compliance account the TR SO2 Group 1

allowances allocated to the TR SO2 Group 1 units at the source in 

accordance with §97.611(a) for the control period in 2013.

(c) By July 1, 2013, the Administrator will record in each TR SO2

Group 1 source's compliance account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units at the source, or in each 

appropriate Allowance Management System account the TR SO2 Group 1

allowances auctioned to TR SO2 Group 1 units, in accordance with 

§97.611(a), or with a SIP revision approved under §52.39(e) or (f) of 

this chapter, for the control period in 2014 and 2015.

(d) By July 1, 2014, the Administrator will record in each TR SO2

Group 1 source's compliance account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units at the source, or in each 

appropriate Allowance Management System account the TR SO2 Group 1
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allowances auctioned to TR SO2 Group 1 units, in accordance with 

§97.611(a), or with a SIP revision approved under §52.39(e) or (f) of 

this chapter, for the control period in 2016 and 2017.

(e) By July 1, 2015, the Administrator will record in each TR SO2

Group 1 source's compliance account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units at the source, or in each 

appropriate Allowance Management System account the TR SO2 Group 1

allowances auctioned to TR SO2 Group 1 units, in accordance with 

§97.611(a), or with a SIP revision approved under §52.39(e) or (f) of 

this chapter, for the control period in 2018 and 2019.

(f) By July 1, 2016 and July 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 to the TR SO2 Group 1

units at the source, or in each appropriate Allowance Management 

System account the TR SO2 Group 1 allowances auctioned to TR SO2 Group 

1 units, in accordance with §97.611(a), or with a SIP revision 

approved under §52.39(e) and (f) of this chapter, for the control 

period in the fourth year after the year of the applicable 

recordation deadline under this paragraph.

(g) By August 1, 2012 and August 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 to the TR SO2 Group 1

units at the source, or in each appropriate Allowance Management 
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System account the TR SO2 Group 1 allowances auctioned to TR SO2 Group 

1 units, in accordance with §97.612(a)(2) through (8) and (12), or 

with a SIP revision approved under §52.39(e) and (f) of this chapter, 

for the control period in the year of the applicable recordation 

deadline under this paragraph.

(h) By August 1, 2012 and August 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 to the TR SO2 Group 1

units at the source in accordance with §97.612(b)(2) through (8) and 

(12) for the control period in the year of the applicable recordation 

deadline under this paragraph.

(i) By February 15, 2013 and February 15 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 to the TR SO2 Group 1

units at the source in accordance with §97.612(a)(9) through (12),

for the control period in the year before the year of the applicable 

recordation deadline under this paragraph.

(j) By the date on which any allocation or auction results, other 

than an allocation or auction results described in paragraphs (a) 

through (i) of this section, of TR SO2 Group 1 allowances to a 

recipient is made by or are submitted to the Administrator in 

accordance with §97.611 or §97.612 or with a SIP revision approved 

under §52.39(e) or (f) of this chapter, the Administrator will record 
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such allocation or auction results in the appropriate Allowance 

Management System account. 

(k) When recording the allocation or auction of TR SO2 Group 1

allowances to a TR SO2 Group 1 unit or other entity in an Allowance 

Management System 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 or auctioned.

§ 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
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(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 that is 

correctly submitted under §97.622, 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 in 

the transfer. 

(b) A TR SO2 Group 1 allowance transfer to or from a compliance 

account 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 from such compliance account 

under §97.624 for the control period immediately before such 

allowance transfer deadline.
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(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 non-recordation.

§ 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 such control period or a control period in a 

prior year; and
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(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 in a given year, the 

Administrator will deduct from each source’s 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 a given 

year in accordance with paragraph (b) or (d) of this section. In 
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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 

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 
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amount of TR SO2 Group 1 allowances, allocated for a control period in 

a prior year or the control period in the year of the excess 

emissions or 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 the 

owners and operators of a group of one or more TR SO2 Group 1 sources 

and units in a State (and Indian country within the borders of such 

State) only if the TR SO2 Group 1 allowances: 

(1) Were allocated for a control period in a prior year or the 

control period in the given year or in the immediately following 

year; and

(2) Are held in the assurance account, established by the 

Administrator for such owners and operators of such group of TR SO2

Group 1 sources and units in such State (and Indian country within 

the borders of such State) under paragraph (b)(3) of this section, as 

of the deadline established in paragraph (b)(4) of this section. 
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(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, 2013 and June 1 of each year thereafter, the 

Administrator will:

(i) Calculate, for each State (and Indian country within the borders 

of such State), the total SO2 emissions from all TR SO2 Group 1 units 

at TR SO2 Group 1 sources in the State (and Indian country within the 

borders of such State) during the control period in the year before 

the year of this calculation deadline and the amount, if any, by 

which such total SO2 emissions exceed the State assurance level as 

described in §97.606(c)(2)(iii); and

(ii) Promulgate a notice of data availability of the results of the 

calculations required in paragraph (b)(1)(i) of this section, 

including separate calculations of the SO2 emissions from each TR SO2

Group 1 source. 

(2) For each notice of data availability required in paragraph 

(b)(1)(ii) of this section and for any State (and Indian country 

within the borders of such State) identified in such notice as having 

TR SO2 Group 1 units with total SO2 emissions exceeding the State 
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assurance level for a control period in a given year, as described in 

§97.606(c)(2)(iii):

(i) By July 1 immediately after the promulgation of such notice, the 

designated representative of each TR SO2 Group 1 source in each such 

State (and Indian country within the borders of such State) shall 

submit a statement, in a format prescribed by the Administrator, 

providing for each TR SO2 Group 1 unit (if any) at the source that 

operates during, but is not allocated an amount of TR SO2 Group 1

allowances for, such control period, the unit’s allowable SO2 emission 

rate for such control period and, if such rate is expressed in lb per 

mmBtu, the unit’s heat rate. 

(ii) By August 1 immediately after the promulgation of such notice, 

the Administrator will calculate, for each such State (and Indian 

country within the borders of such State) and such control period and 

each common designated representative for such control period for a 

group of one or more TR SO2 Group 1 sources and units in the State 

(and Indian country within the borders of such State), the common 

designated representative’s share of the total SO2 emissions from all 

TR SO2 Group 1 units at TR SO2 Group 1 sources in the State (and 

Indian country within the borders of such State), the common 

designated representative’s assurance level, and the amount (if any) 

of TR SO2 Group 1 allowances that the owners and operators of such 

group of sources and units must hold in accordance with the 
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calculation formula in §97.606(c)(2)(i) and will promulgate a notice 

of data 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)(2)(ii) of this section and the 

calculations referenced by the relevant notice of data availability 

required in paragraph (b)(1)(i) of this section. 

(A) Objections shall be submitted by the deadline specified in such 

notice and shall be limited to addressing whether the calculations 

referenced in the relevant notice required under paragraph (b)(1)(ii) 

of this section and referenced in the notice required under paragraph 

(b)(2)(ii) of this section are in accordance with §97.606(c)(2)(iii), 

§§97.606(b) and 97.630 through 97.635, the definitions of “common 

designated representative”, “common designated representative’s 

assurance level”, and “common designated representative’s share” in 

§97.602, and the calculation formula in §97.606(c)(2)(i).

(B) 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)(iii)(A) of this section. By October 1 

immediately after the promulgation of such notice, the Administrator 

will promulgate a notice of data availability of any adjustments that 

the Administrator determines to be necessary and the reasons for 
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accepting or rejecting any objections submitted in accordance with 

paragraph (b)(2)(iii)(A) of this section.

(3) For any State (and Indian country within the borders of such 

State) referenced in each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section as having TR SO2 Group 1

units with total SO2 emissions exceeding the State assurance level for 

a control period in a given year, the Administrator will establish 

one assurance account for each set of owners and operators 

referenced, in the notice of data availability required under 

paragraph (b)(2)(iii)(B) of this section, as all of the owners and 

operators of a group of TR SO2 Group 1 sources and units in the State 

(and Indian country within the borders of such State) having a common 

designated representative for such control period and as being 

required to hold TR SO2 Group 1 allowances. 

(4)(i) As of midnight of November 1 immediately after the 

promulgation of each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section, the owners and operators 

described in paragraph (b)(3) of this section shall hold in the 

assurance account established for the them and for the appropriate TR 

SO2 Group 1 sources, TR SO2 Group 1 units, and State (and Indian 

country within the borders of such State) under paragraph (b)(3) of 

this section a total amount of TR SO2 Group 1 allowances, available 

for deduction under paragraph (a) of this section, equal to the 

amount such owners and operators are required to hold with regard to 
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such sources, units and State (and Indian country within the borders 

of such State) as calculated by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowance-holding deadline specified in 

paragraph (b)(4)(i) of this section, if November 1 is not a business 

day, then such allowance-holding deadline shall be midnight of the 

first business day thereafter.

(5) After November 1 (or the date described in paragraph (b)(4)(ii) 

of this section) immediately after the promulgation of each notice of 

data availability required in paragraph (b)(2)(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 determine whether the owners and operators 

described in paragraph (b)(3) of this section hold, in the assurance 

account for the appropriate TR SO2 Group 1 sources, TR SO2 Group 1

units, and State (and Indian country within the borders of such 

State) established under paragraph (b)(3) of this section, the amount 

of TR SO2 Group 1 allowances available under paragraph (a) of this 

section that the owners and operators are required to hold with 

regard to such sources, units, and State (and Indian country within 

the borders of such State) as calculated by the Administrator and 

referenced in the notice required in paragraph (b)(2)(iii)(B) of this 

section.
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(6) Notwithstanding any other provision of this subpart and any 

revision, made by or submitted to the Administrator after the 

promulgation of the notice of data availability required in paragraph 

(b)(2)(iii)(B) of this section for a control period in a given year, 

of any data used in making the calculations referenced in such 

notice, the amounts of TR SO2 Group 1 allowances that the owners and 

operators are required to hold in accordance with §97.606(c)(2)(i) 

for such control period shall continue to be such amounts as 

calculated by the Administrator and referenced in such notice 

required in paragraph (b)(2)(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 and operators are 

required to hold in accordance with the calculation formula in 

§97.606(c)(2)(i) for such control period with regard to the TR SO2

Group 1 sources, TR SO2 Group 1 units, and State (and Indian country 

within the borders of such State) involved, provided that such 

litigation under part 78 of this chapter, or the proceeding under 

part 78 of this chapter that resulted in the decision appealed in 
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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)(iii)(B) of this section.

(ii) If any such data are revised by the owners and operators of a TR 

SO2 Group 1 source and TR SO2 Group 1 unit whose designated 

representative submitted such data under paragraph (b)(2)(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 and operators are required to hold in accordance with the 

calculation formula in §97.606(c)(2)(i) for such control period with 

regard to the TR SO2 Group 1 sources, TR SO2 Group 1 units, and State 

(and Indian country within the borders of such State) involved, 

provided that such litigation was initiated no later than 30 days 

after promulgation of such notice required in paragraph 

(b)(2)(iii)(B) of this section.

(iii) If the revised data are used to recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this section, the amount of TR SO2

Group 1 allowances that the owners and operators are required to hold 

for such control period with regard to the TR SO2 Group 1 sources, TR 

SO2 Group 1 units, and State (and Indian country within the borders of 

such State) involved—
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(A) Where the amount of TR SO2 Group 1 allowances that the owners and 

operators are 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 owners and operators shall hold the 

additional amount of TR SO2 Group 1 allowances in the assurance 

account established by the Administrator for the appropriate TR SO2

Group 1 sources, TR SO2 Group 1 units, and State (and Indian country 

within the borders of such State) under paragraph (b)(3) of this 

section. The owners’ and operators’ failure to hold such additional 

amount, as required, before the new deadline shall not be a violation 

of the Clean Air Act. The owners’ and operators’ 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 owners and operators fail to hold as required as of the new 

deadline, and each day in such control period, shall be a separate 

violation of the Clean Air Act. 

(B) For the owners and operators 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 all accounts 

from which TR SO2 Group 1 allowances were transferred by such owners 

and operators for such control period to the assurance account 

established by the Administrator for the appropriate at TR SO2 Group 1

sources, TR SO2 Group 1 units, and State (and Indian country within 

the borders of such State) under paragraph (b)(3) of this section, a 
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total amount of the TR SO2 Group 1 allowances held in such assurance 

account equal to the amount of the decrease. If TR SO2 Group 1

allowances were transferred to such assurance account from more than 

one account, the amount of TR SO2 Group 1 allowances recorded in each 

such transferor account will be in proportion to the percentage of 

the total amount of TR SO2 Group 1 allowances transferred to such 

assurance account for such control period from such transferor 

account. 

(C) Each TR SO2 Group 1 allowance held under paragraph (b)(6)(iii)(A) 

of this section as a result of recalculation of requirements under 

the TR SO2 Group 1 assurance provisions for such control period must 

be a TR SO2 Group 1 allowance allocated for a control period in a year

before or the year immediately following, or in the same year as, the 

year of such control period. 

§ 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 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, or 97.628.
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§ 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 compliance account or an 

assurance 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 
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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 
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§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 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 SO2 Group 1 unit that commences 

commercial operation before July 1, 2011, 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:

(i) January 1, 2012; or

(ii) 180 calendar days after the date on which the unit commences 

commercial operation.
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(3) 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 shall meet the requirements 

of §§75.4(e)(1) through (e)(4) of this chapter, except that:

(i) Such requirements shall apply to the monitoring systems required 

under §97.630 through §97.635, rather than the monitoring systems 

required under part 75 of this chapter;

(ii) SO2 concentration, stack gas moisture content, stack gas 

volumetric flow rate, and O2 or CO2 concentration data shall be 

determined and reported, rather than the data listed in §75.4(e)(2) 

of this chapter; and

(iii) Any petition for another procedure under §75.4(e)(2) of this 

chapter shall be submitted under §97.635, rather than §75.66.

(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 
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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 to the 

atmosphere without accounting for all such SO2 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 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 
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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 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.
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(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) that is 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 
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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 
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§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”. 
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(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.
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(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. 
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(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 
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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 
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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.
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(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 State or 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. 
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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 paragraphs (b) 

through (e) of 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.
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(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; or

(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 

commence in the quarter covering January 1, 2012 through March 31, 

2012.

(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.
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(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 
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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.
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§ 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. 

(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. 
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(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.

77. Part 97 is amended by adding subpart DDDDD to read as follows:

Subpart DDDDD—TR SO2 Group 2 Trading Program 

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 setasides, Indian country 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 to new units.
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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 compliance accounts and general 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.
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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.

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 

§52.39 of this chapter, as a means of mitigating interstate transport 

of fine particulates and sulfur dioxide.
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§ 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 multi-state 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 determined by the Administrator) 

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, State, or 

permitting authority, in accordance with this subpart and any SIP 

revision submitted by the State and approved by the Administrator 

under §52.39(g), (h), or (i) of this chapter, of the amount of such 

TR SO2 Group 2 allowances to be initially credited, at no cost to the 

recipient, to:

(1) A TR SO2 Group 2 unit;

(2) A new unit set-aside;
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(3) An Indian country new unit set-aside; or

(4) An entity not listed in paragraphs (1) through (3) of this 

definition;

(5) Provided that, if the Administrator, State, or permitting 

authority initially credits, to a TR SO2 Group 2 unit qualifying for 

an initial credit, a credit in the amount of zero TR SO2 Group 2 

allowances, the TR SO2 Group 2 unit will be treated as being allocated 

an amount (i.e., zero) of TR SO2 Group 2 allowances. 

Allowable SO2 emission rate means, for a unit, the most stringent 

State or federal SO2 emission rate limit (in lb/MWhr or, if in 

lb/mmBtu, converted to lb/MWhr by multiplying it by the unit’s heat 

rate in mmBtu/MWhr) 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 2 allowances under the TR SO2 Group 2 Trading Program. Such 

allowances are allocated, recorded, held, deducted, or transferred 

only as whole allowances. 

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.
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Allowance transfer deadline means, for a control period in a given 

year, 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 emissions 

limitation for such control period in accordance with §§97.706 and 

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 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 the respective program. 

Assurance account means an Allowance Management System account, 

established by the Administrator under §97.725(b)(3) for certain 

owners and operators of a group of one or more TR SO2 Group 2 sources

and units in a given State (and Indian country within the borders of 

such State), in which are held TR SO2 Group 2 allowances available for 
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use for a control period in a given year in complying with the TR SO2

Group 2 assurance provisions in accordance with §§97.706 and 97.725. 

Authorized account representative means, for 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, for 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
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(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 pressuretreated, 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.

Business day means a day that does not fall on a weekend or a federal 

holiday.

Certifying official means a natural person who is:
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(1) For a corporation, a president, secretary, treasurer, or vicepresident of 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 “coal” as defined in §72.2 of this chapter.

Coal-derived fuel means any fuel (whether in a solid, liquid, or 

gaseous state) produced by the mechanical, thermal, or chemical 

processing of coal.

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 that is a toppingcycle unit or a bottoming-cycle unit:
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(1) Operating as part of a cogeneration system; and

(2) Producing on an annual average basis—

(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 than 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 requirements in paragraph (2) of this 

definition shall not apply to a calendar year referenced in paragraph 

(2) of this definition during which the unit did not operate at all;

(4) 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
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(5) Provided that, if, throughout its operation during the 12-month 

period or a calendar year referenced in paragraph (2) of this 

definition, a unit is operated as part of a cogeneration system and 

the cogeneration system meets on a system-wide basis the requirement 

in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall 

be deemed to meet such requirement during that 12-month period or 

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 §97.705.

(i) For a unit that is a TR SO2 Group 2 unit under §97.704 on the 

later of January 1, 2005 or the date the unit commences commercial 
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operation as defined in the introductory text of paragraph (1) of 

this definition and that subsequently undergoes a physical change or 

is moved to a new location or 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 January 1, 2005 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 or a different 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 January 1, 2005 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 
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definition and that subsequently undergoes a physical change or is 

moved to a different location or 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 or 

a different 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.

Common designated representative means, with regard to a control 

period in a given year, a designated representative where, as of 

April 1 immediately after the allowance transfer deadline for such 

control period, the same natural person is authorized under 

§§97.713(a) and 97.715(a) as the designated representative for a 

group of one or more TR SO2 Group 2 sources and units located in a 

State (and Indian country within the borders of such State).

Common designated representative’s assurance level means, with regard 

to a specific common designated representative and a State (and 

Indian country within the borders of such State) and control period 

in a given year for which the State assurance level is exceeded as 
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described in §97.706(c)(2)(iii), the common designated 

representative’s share of the State SO2 Group 2 trading budget with 

the variability limit for the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative for a control period in a 

given year:

(1) With regard to a total amount of SO2 emissions from all TR SO2

Group 2 units in a State (and Indian country within the borders of 

such State) during such control period, the total tonnage of SO2

emissions during such control period from a group of one or more TR 

SO2 Group 2 units located in such State (and such Indian country) and 

having the common designated representative for such control period; 

(2) With regard to a State SO2 Group 2 trading budget with the 

variability limit for such control period, the amount (rounded to the 

nearest allowance) equal to the sum of the total amount of TR SO2

Group 2 allowances allocated for such control period to a group of 

one or more TR SO2 Group 2 units located in the State (and Indian 

country within the borders of such State) and having the common 

designated representative for such control period and of the total 

amount of TR SO2 Group 2 allowances purchased by an owner or operator 

of such TR SO2 Group 2 units in an auction for such control period and 

submitted by the State or the permitting authority to the 

Administrator for recordation in the compliance accounts for such TR 
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SO2 Group 2 units in accordance with the TR SO2 Group 2 allowance 

auction provisions in a SIP revision approved by the Administrator 

under §52.39(h) or (i) of this chapter, multiplied by the sum of the 

State SO2 Group 2 trading budget under §97.710(a) and the State’s 

variability limit under §97.710(b) for such control period and 

divided by such State SO2 Group 2 trading budget; 

(3) Provided that, in the case of a unit that operates during, but 

has no amount of TR SO2 Group 2 allowances allocated under §§97.711 

and 97.712 for, such 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 unit’s allowable SO2 emission rate 

applicable to such control period, multiplied by a capacity factor of 

0.85 (if the unit is a boiler combusting any amount of coal or coalderived fuel during such control period), 0.24 (if the unit is a 

simple combustion turbine during such control period), 0.67 (if the 

unit is a combined cycle turbine during such control period), 0.74

(if the unit is an integrated coal gasification combined cycle unit 

during such control period), or 0.36 (for any other unit), 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. 

Common stack means a single flue through which emissions from 2 or 

more units are exhausted.
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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 to 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 a given year in complying with the source's TR SO2 Group 2 

emissions limitation in accordance with §§97.706 and 97.724. 

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 
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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 
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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 the respective program. 

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:

(1) In accordance with this subpart; and

(2) With regard to a period before the unit or source is required to 

measure, record, and report such air pollutants in accordance with 

this subpart, in accordance with part 75 of this chapter.

Excess emissions means any ton of emissions from the TR SO2 Group 2 

units at a TR SO2 Group 2 source during a control period in a given 

year that exceeds the TR SO2 Group 2 emissions limitation for the 

source for such control period.

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 the limitation on “average annual fuel 

consumption of fossil fuel” in §§97.704(b)(2)(i)(B) and (ii), natural 
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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 2005 or any calendar year thereafter.

General account means an Allowance Management System account, 

established under this subpart, that is not a compliance account or 

an assurance account.

Generator means a device that produces electricity.

Gross electrical output means, for 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, for a unit for a specified period of time, the 

product (in mmBtu/time) of the gross calorific value of the fuel (in 

mmBtu/lb) fed into the unit multiplied by the fuel feed rate (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.
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Heat input rate means, for a unit, the amount of heat input (in 

mmBtu) divided by unit operating time (in hr) or, for a unit and 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.

Heat rate means, for a unit, the unit’s maximum design heat input (in 

Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the unit’s 

maximum hourly load.

Indian country means “Indian country” as defined in 18 U.S.C. 1151.

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 
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nameplate capacity and associated energy generated by the unit at the 

end of the period.

Maximum design heat input means, for a unit, the maximum amount of 

fuel per hour (in Btu/hr) that the 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, rounded 

to the nearest tenth) 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 

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 (in MWe, rounded to 

the nearest tenth) as of such completion as specified by the person 

conducting the physical change.
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Natural gas means “natural gas” as defined in §72.2 of this chapter.

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, for a TR SO2 Group 2 source or a TR SO2 Group 2 unit 

at a source respectively, any person who operates, controls, or 

supervises a TR SO2 Group 2 unit at the source or the TR SO2 Group 2 

unit and shall include, but not be limited to, any holding company, 

utility system, or plant manager of such source or unit.

Owner means, for 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; 

and
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(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-the-unit, firm power 

contractual arrangement. 

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, for a unit, 33 percent of 

the 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, auction, transfer, or 

deduction.
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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) The use of reject heat from electricity production in a useful 

thermal energy application or process; or

(2) 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.
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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 that is subject to the TR SO2 Group 2 

Trading Program pursuant to §52.39(a),(c), (g), (h), and (i) 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 
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at least some of the reject heat from the electricity production is 

then used to provide useful thermal energy.

Total energy input means, for a unit, total energy of all forms 

supplied to the 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, for a unit, 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 in accordance with 

subpart AAAAA of this part and §52.38(a) of this chapter (including 

such a program that is revised in a SIP revision approved by the 

Administrator under §52.38(a)(3) or (4) of this chapter or that is 

established in a SIP revision approved by the Administrator under 
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§52.38(a)(5) 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 in 

accordance with subpart BBBBB of this part and §52.38(b) of this 

chapter (including such a program that is revised in a SIP revision 

approved by the Administrator under §52.38(b)(3) or (4) of this 

chapter or that is established in a SIP revision approved by the 

Administrator under §52.38(b)(5) 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 or auctioned by the Administrator under this subpart, or by 

a State or permitting authority under a SIP revision approved by the 

Administrator under §52.39(g), (h), or (i) of this chapter, to emit 

one ton of SO2 during a control period of the specified calendar year 

for which the authorization is allocated or auctioned 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 from 

an assurance account (e.g., in order to account for compliance with 

the assurance provisions under §§97.706 and 97.725). 
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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 in accordance with 

this subpart and §52.39(a), (c), and (g) through (k) of this chapter

(including such a program that is revised in a SIP revision approved 

by the Administrator under §52.39(g) or (h) of this chapter or that 
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is established in a SIP revision approved by the Administrator under 

§52.39(i) 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-fuel-fired boiler, stationary, 

fossil-fuel-fired combustion turbine, or other stationary, fossilfuel-fired combustion device. A unit that undergoes a physical 

change or is moved to a different location or source shall continue 

to be treated as the same unit. A unit (the replaced unit) that is 

replaced by another unit (the replacement unit) at the same or a 

different source shall continue to be treated as the same unit, and 

the replacement unit shall be treated as a separate unit.

Unit operating day means, with regard to a unit, a calendar day in 

which the unit combusts any fuel.

Unit operating hour or hour of unit operation means, with regard to a 

unit, an hour in which the unit combusts any fuel.

Useful power means, with regard to a unit, electricity or mechanical 

energy that the 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).
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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
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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 (and Indian country within the 

borders of such 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, fossilfuel-fired boiler or stationary, fossil-fuel-fired combustion turbine 
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serving at any time, on or after January 1, 2005, 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 (and Indian country within the borders of 

such 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) or (2)(i) of this section shall not be a TR SO2

Group 2 unit:

(1)(i) Any unit:

(A) Qualifying as a cogeneration unit throughout the later of 2005 or 

the 12-month period starting on the date the unit first produces 

electricity and continuing to qualify as a cogeneration unit

throughout each calendar year ending after the later of 2005 or such 

12-month period; and
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(B) Not supplying in 2005 or any calendar year thereafter 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, after qualifying under paragraph (b)(1)(i) of this section 

as not being a TR SO2 Group 2 unit, a unit subsequently no longer 

meets all the requirements of paragraph (b)(1)(i) of this section, 

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. The unit 

shall thereafter continue to be a TR SO2 Group 2 unit.

(2)(i) Any unit:

(A) Qualifying as a solid waste incineration unit throughout the 

later of 2005 or the 12-month period starting on the date the unit 

first produces electricity and continuing to qualify as a solid waste 

incineration unit throughout each calendar year ending after the 

later of 2005 or such 12-month period; and

(B) With an average annual fuel consumption of fossil fuel for the 

first 3 consecutive calendar years of operation starting no earlier 

than 2005 of less than 20 percent (on a Btu basis) and an average 
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annual fuel consumption of fossil fuel for any 3 consecutive calendar 

years thereafter of less than 20 percent (on a Btu basis).

(ii) If, after qualifying under paragraph (b)(2)(i) of this section 

as not being a TR SO2 Group 2 unit, a unit subsequently no longer 

meets all the requirements of paragraph (b)(1)(i) of this section, 

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 2005 for which the 

unit has an average annual fuel consumption of fossil fuel of 20 

percent or more. The unit shall thereafter continue to be a TR SO2

Group 2 unit.

(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 or a SIP revision approved under §52.39(h) or (i) of this 

chapter, 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 
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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 State or 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.
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(a)(1) Any TR SO2 Group 2 unit that is permanently retired 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.
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(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.
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(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 in a given year, 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.

(ii) If total SO2 emissions during a control period in a given year 

from the TR SO2 Group 2 units at a TR SO2 Group 2 source are in excess 

of the TR SO2 Group 2 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 SO2 Group 2 

unit at the source shall hold the TR SO2 Group 2 allowances required 

for deduction under §97.724(d); and

(B) The owners and operators of the source and each TR SO2 Group 2 

unit at the source shall pay any fine, penalty, or assessment or 

comply with any other remedy imposed, for the same violations, under 

the Clean Air Act, and 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 total SO2 emissions 

during a control period in a given year from all TR SO2 Group 2 units 

at TR SO2 Group 2 sources in a State (and Indian country within the 

borders of such State) exceed the State assurance level, then the 

owners and operators of such sources and units in each group of one 

or more sources and units having a common designated representative 

for such control period, where the common designated representative’s 

share of such SO2 emissions during such control period exceeds the 

common designated representative’s assurance level for the State and 

such control period, shall hold (in the assurance account established 

for the owners and operators of such group) TR SO2 Group 2 allowances 

available for deduction for such control period under §97.725(a) in 

an amount equal to two times the product (rounded to the nearest 

whole number), as determined by the Administrator in accordance with 

§97.725(b), of multiplying—
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(A) The quotient of the amount by which the common designated 

representative’s share of such SO2 emissions exceeds the common 

designated representative’s assurance level divided by the sum of the 

amounts, determined for all common designated representatives for 

such sources and units in the State (and Indian country within the 

borders of such State) for such control period, by which each common 

designated representative’s share of such SO2 emissions exceeds the 

respective common designated representative’s assurance level; and

(B) The amount by which total SO2 emissions from all TR SO2 Group 2 

units at TR SO2 Group 2 sources in the State (and Indian country 

within the borders of such State) for such control period exceed the 

State assurance level. 

(ii) The owners and operators 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) Total SO2 emissions from all TR SO2 Group 2 units at TR SO2

Group 2 sources in a State (and Indian country within the borders of 

such State) during a control period in a given year exceed the State 

assurance level if such total SO2 emissions exceed the sum, for such 

control period, of the State SO2 Group 2 trading budget under 

§97.710(a) and the State’s variability limit under §97.710(b).
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(iv) It shall not be a violation of this subpart or of the Clean Air 

Act if total SO2 emissions from all TR SO2 Group 2 units at TR SO2

Group 2 sources in a State (and Indian country within the borders of 

such State) during a control period exceed the State assurance level 

or if a common designated representative’s share of total SO2

emissions from the TR SO2 Group 2 units at TR SO2 Group 2 sources in a 

State (and Indian country within the borders of such State) during a 

control period exceeds the common designated representative’s 

assurance level. 

(v) To the extent the owners and operators fail to hold TR SO2 Group 2 

allowances for a control period in a given year in accordance with 

paragraphs (c)(2)(i) through (iii) of this section, 

(A) The owners and operators 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 owners and operators fail 

to hold for such control period in accordance with paragraphs 

(c)(2)(i) through (iii) 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 under paragraphs (c)(1) and (c)(2) of this section for 
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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.

(4) Vintage of allowances held for compliance. (i) A TR SO2 Group 2

allowance held for compliance with the requirements under paragraph 

(c)(1)(i) of this section for a control period in a given year must 

be a TR SO2 Group 2 allowance that was allocated for such control 

period or a control period in a prior year.

(ii) A TR SO2 Group 2 allowance held for compliance with the 

requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through (iii)

of this section for a control period in a given year must be a TR SO2

Group 2 allowance that was allocated for a control period in a prior 

year or the control period in the given year or in the immediately 

following year.

(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. A TR SO2 Group 2 allowance is a limited 

authorization to emit one ton of SO2 during the control period in one 

year. Such authorization is limited in its use and duration as 

follows:
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(i) Such authorization shall only be used in accordance with the TR 

SO2 Group 2 Trading Program; and 

(ii) Notwithstanding any other provision of this subpart, the 

Administrator has the authority to terminate or limit the use and 

duration of 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 

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 §§97.730 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 
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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 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 certificate of representation 

and documents are superseded because of the submission of a new 

certificate of representation under §97.716 changing the designated 

representative.
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(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.

(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, except as provided in §97.718. 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 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.
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(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, is not a business day, 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.
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§ 97.709 [Reserved]

§ 97.710 State SO2 Group 2 trading budgets, new unit set-asides, 

Indian country new unit set-aside, and variability limits.

(a) The State SO2 Group 2 trading budgets, new unit set-asides, and 

Indian country 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)*

for 2012 and 2013

New unit setaside (tons)

for 2012 and 

2013

Indian country new 

unit set-aside 

(tons)

for 2012 and 2013

Alabama 216,033 4,321 ---

Georgia 158,527 3,171 ---

Kansas 41,528 789 42

Minnesota 41,981 798 42

Nebraska 65,052 2,537 65

South Carolina 88,620 1,683 89

Texas 243,954 11,954 244

State

SO2 Group 2 trading 

budget (tons)*

for 2014 and 

thereafter

New unit setaside (tons)

for 2014 and 

thereafter

Indian country 

new unit setaside (tons)

for 2014 and 

thereafter

Alabama 213,258 4,265 ---

Georgia 95,231 1,905 ---

Kansas 41,528 789 42

Minnesota 41,981 798 42

Nebraska 65,052 2,537 65
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South Carolina 88,620 1,683 89

Texas 243,954 11,954 244

* Each trading budget includes the new unit set-aside and, where 

applicable, the Indian country new unit set-aside and does not 

include the variability limit.

(b) The States’ variability limits for the State SO2 Group 2 trading 

budgets for the control periods in 2012 and thereafter are as 

follows:

State

Variability limits

for 2012 and 2013

Variability limits

for 2014 and thereafter

Alabama 38,886 38,386

Georgia 28,535 17,142

Kansas 7,475 7,475

Minnesota 7,557 7,557

Nebraska 11,709 11,709

South Carolina 15,952 15,952

Texas 43,912 43,912

§ 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 provided in 

a notice of data availability issued by the Administrator. Providing 

an allocation to a unit in such notice does not constitute a 

determination that the unit is a TR SO2 Group 2 unit, and not 
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providing an allocation to a unit in such notice 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 

provided an allocation in the notice of data availability issued 

under paragraph (a)(1) of this section does not operate, starting 

after 2011, during the control period in two consecutive years, such 

unit will not be allocated the TR SO2 Group 2 allowances provided in 

such notice for the unit for the control periods in the fifth year 

after the first such year and in each year after that fifth 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 

State where such unit is located and 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) New unit set-asides. (i) By June 1, 2012 and 

June 1 of each year thereafter, the Administrator will calculate the 

TR SO2 Group 2 allowance allocation to each TR SO2 Group 2 unit in a 

State, in accordance with §97.712(a)(2) through (7) and (12), for the 

control period in the year of the applicable calculation deadline 

under this paragraph and will promulgate a notice of data 

availability of the results of the calculations.
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(ii) For each notice of data availability required in paragraph 

(b)(1)(i) of this section, the Administrator will provide an 

opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR SO2 Group 2 units) are in 

accordance with §97.712(a)(2) through (7) and (12) and §§97.706(b)(2) 

and 97.730 through 97.735. 

(B) The Administrator will adjust the calculations to the extent 

necessary to ensure that they are in accordance with the provisions 

referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(1)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.712(a)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) of this section. 

(iii) If the new unit set-aside for such control period contains any 

TR SO2 Group 2 allowances that have not been allocated in the 

applicable notice of data availability required in paragraph 
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(b)(1)(ii) of this section, the Administrator will promulgate, by 

December 15 immediately after such notice, a notice of data 

availability that identifies any TR SO2 Group 2 units that commenced 

commercial operation during the period starting January 1 of the year 

before the year of such control period and ending November 30 of year 

of such control period.

(iv) For each notice of data availability required in paragraph 

(b)(1)(iii) of this section, the Administrator will provide an 

opportunity for submission of objections to the identification of TR 

SO2 annual units in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(1)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR SO2 annual units in such notice is in accordance with paragraph 

(b)(1)(iii) of this section. 

(B) The Administrator will adjust the identification of TR SO2 Group 2 

units in the each notice of data availability required in paragraph 

(b)(1)(iii) of this section to the extent necessary to ensure that it 

is in accordance with paragraph (b)(1)(iii) of this section and will 

calculate the TR SO2 Group 2 allowance allocation to each TR SO2 Group 

2 unit in accordance with §97.712(a)(9), (10), and (12) and 

§§97.706(b)(2) and 97.730 through 97.735. By February 15 immediately 

after the promulgation of each notice of data availability required 
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in paragraph (b)(1)(iii) of this section, the Administrator will 

promulgate a notice of data availability of any adjustments of the 

identification of TR SO2 Group 2 units that the Administrator 

determines to be necessary, the reasons for accepting or rejecting 

any objections submitted in accordance with paragraph (b)(1)(iv)(A) 

of this section, and the results of such calculations.

(v) To the extent any TR SO2 Group 2 allowances are added to the new 

unit set-aside after promulgation of each notice of data availability 

required in paragraph (b)(1)(iv) of this section, the Administrator 

will promulgate additional notices of data availability, as deemed 

appropriate, of the allocation of such TR SO2 Group 2 allowances in 

accordance with §97.712(a)(10). 

(2) Indian country new unit set-asides. (i) By June 1, 2012 and June 

1 of each year thereafter, the Administrator will calculate the TR SO2

Group 2 allowance allocation to each TR SO2 Group 2 unit in Indian 

country within the borders of a State, in accordance with 

§97.712(b)(2) through (7) and (12), for the control period in the 

year of the applicable calculation deadline under this paragraph and 

will promulgate a notice of data availability of the results of the 

calculations.

(ii) For each notice of data availability required in paragraph 

(b)(2)(i) of this section, the Administrator will provide an 
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opportunity for submission of objections to the calculations 

referenced in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(i) of this 

section and shall be limited to addressing whether the calculations 

(including the identification of the TR SO2 Group 2 units) are in 

accordance with §97.712(b)(2) through (7) and (12) and §§97.706(b)(2) 

and 97.730 through 97.735. 

(B) 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)(ii)(A) of this section. By August 1 

immediately after the promulgation of each notice of data 

availability required in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice of data availability of any 

adjustments that the Administrator determines to be necessary with 

regard to allocations under §97.712(b)(2) through (7) and (12) and 

the reasons for accepting or rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) of this section. 

(iii) If the Indian country new unit set-aside for such control 

period contains any TR SO2 Group 2 allowances that have not been 

allocated in the applicable notice of data availability required in 

paragraph (b)(2)(ii) of this section, the Administrator will 

promulgate, by December 15 immediately after such notice, a notice of 
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data availability that identifies any TR SO2 Group 2 units that 

commenced commercial operation during the period starting January 1 

of the year before the year of such control period and ending 

November 30 of year of such control period.

(iv) For each notice of data availability required in paragraph 

(b)(2)(iii) of this section, the Administrator will provide an 

opportunity for submission of objections to the identification of TR 

SO2 annual units in such notice. 

(A) Objections shall be submitted by the deadline specified in each 

notice of data availability required in paragraph (b)(2)(iii) of this 

section and shall be limited to addressing whether the identification 

of TR SO2 annual units in such notice is in accordance with paragraph 

(b)(2)(iii) of this section. 

(B) The Administrator will adjust the identification of TR SO2 Group 2 

units in the each notice of data availability required in paragraph 

(b)(2)(iii) of this section to the extent necessary to ensure that it 

is in accordance with paragraph (b)(2)(iii) of this section and will 

calculate the TR SO2 Group 2 allowance allocation to each TR SO2 Group 

2 unit in accordance with §97.712(b)(9), (10), and (12) and 

§§97.706(b)(2) and 97.730 through 97.735. By February 15 immediately 

after the promulgation of each notice of data availability required 

in paragraph (b)(2)(iii) of this section, the Administrator will 

promulgate a notice of data availability of any adjustments of the 
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identification of TR SO2 Group 2 units that the Administrator 

determines to be necessary, the reasons for accepting or rejecting 

any objections submitted in accordance with paragraph (b)(2)(iv)(A) 

of this section, and the results of such calculations. 

(v) To the extent any TR SO2 Group 2 allowances are added to the 

Indian country new unit set-aside after promulgation of each notice 

of data availability required in paragraph (b)(2)(iv) of this 

section, the Administrator will promulgate additional notices of data 

availability, as deemed appropriate, of the allocation of such TR SO2

Group 2 allowances in accordance with §97.712(b)(10). 

(c) Units incorrectly allocated TR SO2 Group 2 allowances. (1) 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, or under a provision of a SIP revision 

approved §52.39(g), (h), or (i) of this chapter, where such control 

period and the recipient are covered by the provisions of paragraph 

(c)(1)(i) of this section or were allocated under §97.712(a)(2) 

through (7), (9), and (12) and (b)(2) through (7), (9), and (12), or 

under a provision of a SIP revision approved §52.39(h) or (i) of this 

chapter, where such control period and the recipient are covered by 

the provisions of paragraph (c)(1)(ii) of this section, then the 

Administrator will notify the designated representative of the 

recipient and will act in accordance with the procedures set forth in 

paragraphs (c)(2) through (5) of this section:
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(i)(A) The recipient is not actually a TR SO2 Group 2 unit under 

§97.704 as of January 1, 2012 and is allocated TR SO2 Group 2 

allowances for such control period or, in the case of an allocation 

under a provision of a SIP revision approved under §52.39(g), (h), or 

(i) of this chapter, the recipient is not actually a TR SO2 Group 2 

unit as of January 1, 2012 and is allocated TR SO2 Group 2 allowances 

for such control period that the SIP revision provides should be 

allocated only to recipients that are TR SO2 Group 2 units as of 

January 1, 2012; or

(B) The recipient is not located as of January 1 of the control 

period in the State from whose SO2 Group 2 trading budget the TR SO2

Group 2 allowances allocated under paragraph (a) of this section, or 

under a provision of a SIP revision approved under §52.39(g), (h), or 

(i) of this chapter, were allocated for such control period. 

(ii) The recipient is not actually a TR SO2 Group 2 unit under §97.704 

as of January 1 of such control period and is allocated TR SO2 Group 2 

allowances for such control period or, in the case of an allocation 

under a provision of a SIP revision approved under §52.39(g), (h), or 

(i) of this chapter, the recipient is not actually a TR SO2 Group 2 

unit as of January 1 of such control period and is allocated TR SO2

Group 2 allowances for such control period that the SIP revision 

provides should be allocated only to recipients that are TR SO2 Group 

2 units as of January 1 of such control period. 
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(2) Except as provided in paragraph (c)(3) or (4) of this section, 

the Administrator will not record such TR SO2 Group 2 allowances under 

§97.721.

(3) If the Administrator already recorded such TR SO2 Group 2 

allowances under §97.721 and if the Administrator makes the 

determination under paragraph (c)(1) of this section 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.

(4) If the Administrator already recorded such TR SO2 Group 2 

allowances under §97.721 and if the Administrator makes the 

determination under paragraph (c)(1) of this section 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. 

(5)(i) With regard to the TR SO2 Group 2 allowances that are not 

recorded, or that are deducted as an incorrect allocation, in 
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accordance with paragraphs (c)(2) and (3) of this section for a 

recipient under paragraph (c)(1)(i) of this section, the 

Administrator will:

(A) Transfer such TR SO2 Group 2 allowances to the new unit set-aside 

for such control period for the State from whose SO2 Group 2 trading 

budget the TR SO2 Group 2 allowances were allocated; or

(B) If the State has a SIP revision approved under §52.39(h) or (i) 

covering such control period, include such TR SO2 Group 2 allowances 

in the portion of the State SO2 Group 2 trading budget that may be 

allocated for such control period in accordance with such SIP 

revision. 

(ii) With regard to the TR SO2 Group 2 allowances that were not 

allocated from the Indian country new unit set-aside for such control 

period and that are not recorded, or that are deducted as an 

incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 

this section for a recipient under paragraph (c)(1)(ii) of this 

paragraph, the Administrator will:

(A) Transfer such TR SO2 Group 2 allowances to the new unit set-aside 

for such control period; or

(B) If the State has a SIP revision approved under §52.39(h) or (i) 

covering such control period, include such TR SO2 Group 2 allowances 

in the portion of the State SO2 Group 2 trading budget that may be 
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Page 1216 of 1293

allocated for such control period in accordance with such SIP 

revision. 

(iii) With regard to the TR SO2 Group 2 allowances that were allocated 

from the Indian country new unit set-aside for such control period 

and that are not recorded, or that are deducted as an incorrect 

allocation, in accordance with paragraphs (c)(2) and (3) of this 

section for a recipient under paragraph (c)(1)(ii) of this paragraph, 

the Administrator will transfer such TR SO2 Group 2 allowances to the 

Indian country new unit set-aside for such control period.

§ 97.712 TR SO2 Group 2 allowance allocations to new units.

(a) For each control period in 2012 and thereafter and for the TR SO2

Group 2 units in each State, the Administrator will allocate TR SO2

Group 2 allowances to the TR SO2 Group 2 units as follows:

(1) The TR SO2 Group 2 allowances will be allocated to the following 

TR SO2 Group 2 units, except as provided in paragraph (a)(10) of this 

section:

(i) TR SO2 Group 2 units that are not allocated an amount of TR SO2

Group 2 allowances in the notice of data availability issued under 

§97.711(a)(1); 

(ii) TR SO2 Group 2 units whose allocation of an amount of TR SO2

Group 2 allowances for such control period in the notice of data 
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availability issued under §97.711(a)(1) is covered by §97.711(c)(2) 

or (3);

(iii) TR SO2 Group 2 units that are allocated an amount of TR SO2

Group 2 allowances for such control period in the notice of data 

availability issued under §97.711(a)(1), which allocation is 

terminated for such control period pursuant to §97.711(a)(2), and 

that operate during the control period immediately preceding such 

control period; or

(iv) For purposes of paragraph (a)(9) of this section, TR SO2 Group 2 

units under §97.711(c)(1)(ii) whose allocation of an amount of TR SO2

Group 2 allowances for such control period in the notice of data 

availability issued under §97.711(b)(1)(ii)(B) is covered by 

§97.711(c)(2) or (3). 

(2) The Administrator will establish a separate new unit set-aside 

for the State for each such control period. Each such new unit setaside 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) and will be allocated additional TR SO2 Group 2 allowances 

(if any) in accordance with §§97.711(a)(2) and (c)(5) and paragraph 

(b)(10) of this section.

(3) The Administrator will determine, for each TR SO2 Group 2 unit 

described in paragraph (a)(1) of this section, an allocation of TR SO2
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Group 2 allowances for the later of the following control periods and 

for each subsequent control period:

(i) The control period in 2012;

(ii) The first control period after the control period in which the 

TR SO2 Group 2 unit commences commercial operation; 

(iii) For a unit described in paragraph (a)(1)(ii) of this section, 

the first control period in which the TR SO2 Group 2 unit operates in 

the State after operating in another jurisdiction and for which the 

unit is not already allocated one or more TR SO2 Group 2 allowances; 

and

(iv) For a unit described in paragraph (a)(1)(iii) of this section, 

the first control period after the control period in which the unit 

resumes operation. 

(4)(i) The allocation to each TR SO2 annual unit described in 

paragraph (a)(1)(i) through (iii) of this section and for each 

control period described in paragraph (a)(3) of this section will be 

an amount equal to the unit’s total tons of SO2 emissions during the 

immediately preceding control period.

(ii) The Administrator will adjust the allocation amount in paragraph 

(a)(4)(i) in accordance with paragraphs (a)(5) through (7) and (12) 

of this section.
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(5) The Administrator will calculate the sum of the TR SO2 Group 2 

allowances determined for all such TR SO2 Group 2 units under 

paragraph (a)(4)(i) of this section in the State for such control 

period.

(6) If the amount of TR SO2 Group 2 allowances in the new unit setaside for the State for such control period is greater than or equal 

to the sum under paragraph (a)(5) of this section, then the 

Administrator will allocate the amount of TR SO2 Group 2 allowances 

determined for each such TR SO2 Group 2 unit under paragraph (a)(4)(i) 

of this section.

(7) If the amount of TR SO2 Group 2 allowances in the new unit setaside for the State for such control period is less than the sum 

under paragraph (a)(5) of this section, then the Administrator will 

allocate to each such TR SO2 Group 2 unit the amount of the TR SO2

Group 2 allowances determined under paragraph (a)(4)(i) of this 

section for the unit, multiplied by the amount of TR SO2 Group 2 

allowances in the new unit set-aside for such control period, divided 

by the sum under paragraph (a)(5) of this section, and rounded to the 

nearest allowance.

(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.711(b)(1)(i) and (ii), of the amount of TR SO2 Group 2 allowances 

allocated under paragraphs (a)(2) through (7) and (12) of this 
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section for such control period to each TR SO2 Group 2 unit eligible 

for such allocation.

(9) If, after completion of the procedures under paragraphs (a)(5) 

through (8) of this section for such control period, any unallocated 

TR SO2 Group 2 allowances remain in the new unit set-aside for the 

State for such control period, the Administrator will allocate such 

TR SO2 Group 2 allowances as follows--

(i) The Administrator will determine, for each unit described in 

paragraph (a)(1) of this section that commenced commercial operation 

during the period starting January 1 of the year before the year of 

such control period and ending November 30 of year of such control 

period, the positive difference (if any) between the unit’s emissions 

during such control period and the amount of TR SO2 Group 2 allowances 

referenced in the notice of data availability required under 

§97.711(b)(1)(ii) for the unit for such control period;

(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (a)(9)(i) of this section;

(iii) If the amount of unallocated TR SO2 Group 2 allowances remaining 

in the new unit set-aside for the State for such control period is 

greater than or equal to the sum determined under paragraph 

(a)(9)(ii) of this section, then the Administrator will allocate the 
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amount of TR SO2 Group 2 allowances determined for each such TR SO2

Group 2 unit under paragraph (a)(9)(i) of this section; and

(iv) If the amount of unallocated TR SO2 Group 2 allowances remaining 

in the new unit set-aside for the State for such control period is 

less than the sum under paragraph (a)(9)(ii) of this section, then 

the Administrator will allocate to each such TR SO2 Group 2 unit the 

amount of the TR SO2 Group 2 allowances determined under paragraph 

(a)(9)(i) of this section for the unit, multiplied by the amount of 

unallocated TR SO2 Group 2 allowances remaining in the new unit setaside for such control period, divided by the sum under paragraph 

(a)(9)(ii) of this section, and rounded to the nearest allowance.

(10) If, after completion of the procedures under paragraphs (a)(9) 

and (12) of this section for such control period, any unallocated TR 

SO2 Group 2 allowances remain in the new unit set-aside for the State 

for such control period, the Administrator will allocate to each TR 

SO2 Group 2 unit that is in the State, is allocated an amount of TR 

SO2 Group 2 allowances in the notice of data availability issued under 

§97.711(a)(1), 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 sum 
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of the amounts of tons in such new unit set-aside and the Indian 

country new unit set-aside for the State for such control period, and 

rounded to the nearest allowance.

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.711(b)(1)(iii), (iv), and (v), of the amount of TR SO2 Group 2 

allowances allocated under paragraphs (a)(9), (10), and (12) of this 

section for such control period to each TR SO2 Group 2 unit eligible 

for such allocation.

(12)(i) Notwithstanding the requirements of paragraphs (a)(2) through 

(11) of this section, if the calculations of allocations of a new 

unit set-aside for a control period in a given year under paragraph 

(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this 

section, or paragraphs (a)(6), (9)(iii), and (10) of this section 

would otherwise result in total allocations of such new unit setaside exceeding the total amount of such new unit set-aside, then the 

Administrator will adjust the results of the calculations under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 

follows. The Administrator will list the TR SO2 Group 2 units in 

descending order based on the amount of such units’ allocations under 

paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, 

and, in cases of equal allocation amounts, in alphabetical order of 

the relevant source’s name and numerical order of the relevant unit’s 

identification number, and will reduce each unit’s allocation under 
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paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, by 

one TR SO2 Group 2 allowance (but not below zero) in the order in 

which the units are listed and will repeat this reduction process as 

necessary, until the total allocations of such new unit set-aside 

equal the total amount of such new unit set-aside. 

(ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 

of this section, if the calculations of allocations of a new unit 

set-aside for a control period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section would otherwise result in 

a total allocations of such new unit set-aside less than the total 

amount of such new unit set-aside, then the Administrator will adjust 

the results of the calculations under paragraph (a)(10) of this 

section, as follows. The Administrator will list the TR SO2 Group 2

units in descending order based on the amount of such units’ 

allocations under paragraph (a)(10) of this section and, in cases of 

equal allocation amounts, in alphabetical order of the relevant 

source’s name and numerical order of the relevant unit’s 

identification number, and will increase each unit’s allocation under 

paragraph (a)(10) of this section by one TR SO2 Group 2 allowance in 

the order in which the units are listed and will repeat this increase 

process as necessary, until the total allocations of such new unit 

set-aside equal the total amount of such new unit set-aside. 

(b) For each control period in 2012 and thereafter and for the TR SO2

Group 2 units located in Indian country within the borders of each 
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State, the Administrator will allocate TR SO2 Group 2 allowances to 

the TR SO2 Group 2 units as follows: 

(1) The TR SO2 Group 2 allowances will be allocated to the following 

TR SO2 Group 2 units, except as provided in paragraph (b)(10) of this 

section:

(i) TR SO2 Group 2 units that are not allocated an amount of TR SO2

Group 2 allowances in the notice of data availability issued under 

§97.711(a)(1); or

(ii) For purposes of paragraph (b)(9) of this section, TR SO2 Group 2 

units under §97.711(c)(1)(ii) whose allocation of an amount of TR SO2

Group 2 allowances for such control period in the notice of data 

availability issued under §97.711(b)(2)(ii)(B) is covered by 

§97.711(c)(2) or (3). 

(2) The Administrator will establish a separate Indian country new 

unit set-aside for the State for each such control period. Each such 

Indian country 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) and will be allocated additional 

TR SO2 Group 2 allowances (if any) in accordance with §97.711(c)(5).

(3) The Administrator will determine, for each TR SO2 Group 2 unit 

described in paragraph (b)(1) of this section, an allocation of TR SO2
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Group 2 allowances for the later of the following control periods and 

for each subsequent control period:

(i) The control period in 2012; and

(ii) The first control period after the control period in which the 

TR SO2 Group 2 unit commences commercial operation.

(4)(i) The allocation to each TR SO2 annual unit described in 

paragraph (b)(1)(i) of this section and for each control period 

described in paragraph (b)(3) of this section will be an amount equal 

to the unit’s total tons of SO2 emissions during the immediately 

preceding control period.

(ii) The Administrator will adjust the allocation amount in paragraph 

(b)(4)(i) in accordance with paragraphs (b)(5) through (7) and (12)

of this section. 

(5) The Administrator will calculate the sum of the TR SO2 Group 2 

allowances determined for all such TR SO2 Group 2 units under 

paragraph (b)(4)(i) of this section in Indian country within the 

borders of the State for such control period.

(6) If the amount of TR SO2 Group 2 allowances in the Indian country 

new unit set-aside for the State for such control period is greater 

than or equal to the sum under paragraph (b)(5) of this section, then 

the Administrator will allocate the amount of TR SO2 Group 2 
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Page 1226 of 1293

allowances determined for each such TR SO2 Group 2 unit under 

paragraph (b)(4)(i) of this section.

(7) If the amount of TR SO2 Group 2 allowances in the Indian country 

new unit set-aside for the State for such control period is less than 

the sum under paragraph (b)(5) of this section, then the 

Administrator will allocate to each such TR SO2 Group 2 unit the 

amount of the TR SO2 Group 2 allowances determined under paragraph 

(b)(4)(i) of this section for the unit, multiplied by the amount of 

TR SO2 Group 2 allowances in the Indian country new unit set-aside for 

such control period, divided by the sum under paragraph (b)(5) of 

this section, and rounded to the nearest allowance.

(8) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.711(b)(2)(i) and (ii), of the amount of TR SO2 Group 2 allowances 

allocated under paragraphs (b)(2) through (7) and (12) of this 

section for such control period to each TR SO2 Group 2 unit eligible 

for such allocation.

(9) If, after completion of the procedures under paragraphs (b)(5) 

through (8) of this section for such control period, any unallocated 

TR SO2 Group 2 allowances remain in the Indian country new unit setaside for the State for such control period, the Administrator will 

allocate such TR SO2 Group 2 allowances as follows--
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(i) The Administrator will determine, for each unit described in 

paragraph (b)(1) of this section that commenced commercial operation 

during the period starting January 1 of the year before the year of 

such control period and ending November 30 of year of such control 

period, the positive difference (if any) between the unit’s emissions 

during such control period and the amount of TR SO2 Group 2 allowances 

referenced in the notice of data availability required under 

§97.711(b)(2)(ii) for the unit for such control period;

(ii) The Administrator will determine the sum of the positive 

differences determined under paragraph (b)(9)(i) of this section;

(iii) If the amount of unallocated TR SO2 Group 2 allowances remaining 

in the Indian country new unit set-aside for the State for such 

control period is greater than or equal to the sum determined under 

paragraph (b)(9)(ii) of this section, then the Administrator will 

allocate the amount of TR SO2 Group 2 allowances determined for each 

such TR SO2 Group 2 unit under paragraph (b)(9)(i) of this section; 

and

(iv) If the amount of unallocated TR SO2 Group 2 allowances remaining 

in the Indian country new unit set-aside for the State for such 

control period is less than the sum under paragraph (b)(9)(ii) of 

this section, then the Administrator will allocate to each such TR SO2

Group 2 unit the amount of the TR SO2 Group 2 allowances determined 

under paragraph (b)(9)(i) of this section for the unit, multiplied by 
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the amount of unallocated TR SO2 Group 2 allowances remaining in the 

Indian country new unit set-aside for such control period, divided by 

the sum under paragraph (b)(9)(ii) of this section, and rounded to 

the nearest allowance.

(10) If, after completion of the procedures under paragraphs (b)(9)

and (12) of this section for such control period, any unallocated TR 

SO2 Group 2 allowances remain in the Indian country new unit set-aside 

for the State for such control period, the Administrator will:

(i) Transfer such unallocated TR SO2 Group 2 allowances to the new 

unit set-aside for the State for such control period; or 

(ii) If the State has a SIP revision approved under §52.39(g), (h), 

or (i) of this chapter covering such control period, include such 

unallocated TR SO2 Group 2 allowances in the portion of the State SO2

Group 2 trading budget that may be allocated for such control period 

in accordance with such SIP revision. 

(11) The Administrator will notify the public, through the 

promulgation of the notices of data availability described in 

§97.711(b)(2)(iii), (iv), and (v), of the amount of TR SO2 Group 2 

allowances allocated under paragraphs (b)(9), (10), and (12) of this 

section for such control period to each TR SO2 Group 2 unit eligible 

for such allocation.
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(12)(i) Notwithstanding the requirements of paragraphs (b)(2) through 

(11) of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 

paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) of 

this section, or paragraphs (b)(6), (9)(iii), and (10) of this 

section would otherwise result in total allocations of such Indian 

country new unit set-aside exceeding the total amount of such Indian 

country new unit set-aside, then the Administrator will adjust the 

results of the calculations under paragraph (b)(7), (9)(iv), or (10) 

of this section, as applicable, as follows. The Administrator will 

list the TR SO2 Group 2 units in descending order based on the amount 

of such units’ allocations under paragraph (b)(7), (9)(iv), or (10) 

of this section, as applicable, and, in cases of equal allocation 

amounts, in alphabetical order of the relevant source’s name and 

numerical order of the relevant unit’s identification number, and 

will reduce each unit’s allocation under paragraph (b)(7), (9)(iv), 

or (10) of this section, as applicable, by one TR SO2 Group 2

allowance (but not below zero) in the order in which the units are 

listed and will repeat this reduction process as necessary, until the 

total allocations of such Indian country new unit set-aside equal the 

total amount of such Indian country new unit set-aside. 

(ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 

of this section, if the calculations of allocations of an Indian 

country new unit set-aside for a control period in a given year under 
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paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 

result in a total allocations of such Indian country new unit setaside less than the total amount of such Indian country new unit setaside, then the Administrator will adjust the results of the 

calculations under paragraph (b)(10) of this section, as follows. 

The Administrator will list the TR SO2 Group 2 units in descending 

order based on the amount of such units’ allocations under paragraph 

(b)(10) of this section and, in cases of equal allocation amounts, in 

alphabetical order of the relevant source’s name and numerical order 

of the relevant unit’s identification number, and will increase each 

unit’s allocation under paragraph (b)(10) of this section by one TR 

SO2 Group 2 allowance in the order in which the units are listed and 

will repeat this increase process as necessary, until the total 

allocations of such Indian country new unit set-aside equal the total 

amount of such Indian country new unit set-aside. 

§ 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 
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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.
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(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, 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” (as distinguished from 

the term “common designated representative”) is used in this subpart, 

the term shall be construed to include the designated representative 

or any alternate designated representative.
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§ 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 
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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; changes in units at 

the source.

(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 
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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 at the 

source 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 at the source, 

including the addition or removal of an 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 reflect the 

change.

(d) Changes in units at the source. Within 30 days of any change in 

which units are located at a TR SO2 Group 2 source (including the 

addition or removal of a unit), the designated representative or any 

alternate designated representative shall submit a certificate of 
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representation under §97.716 amending the list of units to reflect 

the change. 

(1) If the change is the addition of a unit that operated (other than 

for purposes of testing by the manufacturer before initial 

installation) before being located at the source, then the 

certificate of representation shall identify, in a format prescribed 

by the Administrator, the entity from whom the unit was purchased or 

otherwise obtained (including name, address, telephone number, and 

facsimile number (if any)), the date on which the unit was purchased 

or otherwise obtained, and the date on which the unit became located 

at the source.

(2) If the change is the removal of a unit, then the certificate of 

representation shall identify, in a format prescribed by the 

Administrator, the entity to which the unit was sold or that 

otherwise obtained the unit (including name, address, telephone 

number, and facsimile number (if any)), the date on which the unit 

was sold or otherwise obtained, and the date on which the unit became 

no longer located at the source. 

§ 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:
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(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, actual or projected date of commencement of commercial 

operation, and a statement of whether such source is located in 

Indian Country. If a projected date of commencement of commercial 

operation is provided, the actual date of commencement of commercial 

operation shall be provided when such information becomes available.

(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 
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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 decision or 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-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 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 paragraph (a) of this section, 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 
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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 a natural person 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:
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(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 in this section 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 
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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 compliance accounts, assurance accounts, 

and general accounts.

(a) Compliance accounts. Upon receipt of a complete certificate of 

representation under §97.716, the Administrator will establish a 
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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) Assurance accounts. The Administrator will establish assurance 

accounts for certain owners and operators and States in accordance 

with §97.725(b)(3). 

(c) 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. 
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(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 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
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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 decision or order 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 
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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 

decision or order issued to the authorized account representative or 

alternate authorized account representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph (c)(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 
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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 (c)(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 
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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 (c)(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.
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(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 or removal of a 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 (c)(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 (c)(4)(i) 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 SO2 Group 2 Trading Program.
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(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 a natural person to make an 

electronic submission to the Administrator in accordance with 

paragraph (c)(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:
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(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 in this section as an “agent”);

(C) For each such natural person, a list of the type or types of 

electronic submissions under paragraph (c)(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(c)(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 
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delegation under 40 CFR 97.720(c)(5)(iv), I agree to maintain an email 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(c)(5) is terminated.”.

(iv) A notice of delegation submitted under paragraph (c)(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 (c)(5)(iii)(D) of this section and made in accordance with 

a notice of delegation effective under paragraph (c)(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) Closing a general account. (i) The authorized account 

representative or alternate authorized account representative of a 

general account may submit to the Administrator a request to close 
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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 after 30 days after the notice is sent. The 

account will be closed after the 30-day period unless, before the end 

of the 30-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.

(d) Account identification. The Administrator will assign a unique 

identifying number to each account established under paragraph (a), 

(b), or (c) of this section.

(e) Responsibilities of authorized account representative and 

alternate authorized account representative. After the establishment 

of a compliance account or general account, the Administrator will 

accept or act on a submission pertaining to the account, including, 
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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 (c)(2)(ii) and (c)(5) of this section. 

§ 97.721 Recordation of TR SO2 Group 2 allowance allocations and 

auction results.

(a) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR SO2 Group 2 

source's compliance account the TR SO2 Group 2 allowances allocated to 

the TR SO2 Group 2 units at the source in accordance with §97.711(a) 

for the control period in 2012.

(b) By [INSERT DATE 90 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], the Administrator will record in each TR SO2 Group 2 

source's compliance account the TR SO2 Group 2 allowances allocated to 

the TR SO2 Group 2 units at the source in accordance with §97.711(a) 

for the control period in 2013, unless the State in which the source 

is located notifies the Administrator in writing by [INSERT DATE 70 

DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER] of the State’s 

intent to submit to the Administrator a complete SIP revision by 

April 1, 2012 meeting the requirements of §52.39(g)(1) through (4) of 

this chapter.
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(1) If, by April 1, 2012, the State does not submit to the 

Administrator such complete SIP revision, the Administrator will 

record by April 15, 2012 in each TR SO2 Group 2 source's compliance 

account the TR SO2 Group 2 allowances allocated to the TR SO2 Group 2 

units at the source in accordance with §97.711(a) for the control 

period in 2013.

(2) If the State submits to the Administrator by April 1, 2012, and 

the Administrator approves by October 1, 2012, such complete SIP 

revision, the Administrator will record by October 1, 2012 in each TR 

SO2 Group 2 source's compliance account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units at the source as provided in 

such approved, complete SIP revision for the control period in 2013.

(3) If the State submits to the Administrator by April 1, 2012, and 

the Administrator does not approve by October 1, 2012, such complete 

SIP revision, the Administrator will record by October 1, 2012 in 

each TR SO2 Group 2 source's compliance account the TR SO2 Group 2 

allowances allocated to the TR SO2 Group 2 units at the source in 

accordance with §97.711(a) for the control period in 2013.

(c) By July 1, 2013, the Administrator will record in each TR SO2

Group 2 source's compliance account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units at the source, or in each 

appropriate Allowance Management System account the TR SO2 Group 2

allowances auctioned to TR SO2 Group 2 units, in accordance with 
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§97.711(a), or with a SIP revision approved under §52.39(h) or (i) of 

this chapter, for the control period in 2014 and 2015.

(d) By July 1, 2014, the Administrator will record in each TR SO2

Group 2 source's compliance account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units at the source, or in each 

appropriate Allowance Management System account the TR SO2 Group 2

allowances auctioned to TR SO2 Group 2 units, in accordance with 

§97.711(a), or with a SIP revision approved under §52.39(h) or (i) of 

this chapter, for the control period in 2016 and 2017.

(e) By July 1, 2015, the Administrator will record in each TR SO2

Group 2 source's compliance account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units at the source, or in each 

appropriate Allowance Management System account the TR SO2 Group 2

allowances auctioned to TR SO2 Group 2 units, in accordance with 

§97.711(a), or with a SIP revision approved under §52.39(h) or (i) of 

this chapter, for the control period in 2018 and 2019.

(f) By July 1, 2016 and July 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 to the TR SO2 Group 2 

units at the source, or in each appropriate Allowance Management 

System account the TR SO2 Group 2 allowances auctioned to TR SO2 Group 

2 units, in accordance with §97.711(a), or with a SIP revision 

approved under §52.39(h) and (i) of this chapter, for the control 
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period in the fourth year after the year of the applicable 

recordation deadline under this paragraph.

(g) By August 1, 2012 and August 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 to the TR SO2 Group 2 

units at the source, or in each appropriate Allowance Management 

System account the TR SO2 Group 2 allowances auctioned to TR SO2 Group 

2 units, in accordance with §97.712(a)(2) through (8) and (12), or 

with a SIP revision approved under §52.39(h) and (i) of this chapter, 

for the control period in the year of the applicable recordation 

deadline under this paragraph.

(h) By August 1, 2012 and August 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 to the TR SO2 Group 2 

units at the source in accordance with §97.712(b)(2) through (8) and 

(12) for the control period in the year of the applicable recordation 

deadline under this paragraph.

(i) By February 15, 2013 and February 15 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 to the TR SO2 Group 2

units at the source in accordance with §97.712(a)(9) through (12),

for the control period in the year before the year of the applicable 

recordation deadline under this paragraph.
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(j) By the date on which any allocation or auction results, other 

than an allocation or auction results, described in paragraphs (a) 

through (i) of this section, of TR SO2 Group 2 allowances to a 

recipient is made by or are submitted to the Administrator in 

accordance with §97.711 or §97.712 or with a SIP revision approved 

under §52.39(h) or (i) of this chapter, the Administrator will record 

such allocation or auction results in the appropriate Allowance 

Management System account. 

(k) When recording the allocation or auction of TR SO2 Group 2 

allowances to a TR SO2 Group 2 unit or other entity in an Allowance 

Management System 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 or auctioned.

§ 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:
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(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 that is 

correctly submitted under §97.722, 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 in 

the transfer. 

(b) A TR SO2 Group 2 allowance transfer to or from a compliance 

account 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 
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Administrator completes the deductions from such compliance account 

under §97.724 for the control period immediately before such 

allowance transfer 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 non-recordation.

§ 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:
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(1) Were allocated for such control period or a control period in 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 in a given year, the 

Administrator will deduct from each source’s 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 
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for emissions or excess emissions for a control period in a given 

year 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 

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 
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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 a control period in 

a prior year or the control period in the year of the excess 

emissions or 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 the 

owners and operators of a group of one or more TR SO2 Group 2 sources 

and units in a State (and Indian country within the borders of such 

State) only if the TR SO2 Group 2 allowances: 

(1) Were allocated for a control period in a prior year or the 

control period in the given year or in the immediately following 

year; and

(2) Are held in the assurance account, established by the 

Administrator for such owners and operators of such group of TR SO2

Group 2 sources and units in such State (and Indian country within 
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the borders of such State) under paragraph (b)(3) of this section, as 

of the deadline established in paragraph (b)(4) 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, 2013 and June 1 of each year thereafter, the 

Administrator will:

(i) Calculate, for each State (and Indian country within the borders 

of such State), the total SO2 emissions from all TR SO2 Group 2 units 

at TR SO2 Group 2 sources in the State (and Indian country within the 

borders of such State) during the control period in the year before 

the year of this calculation deadline and the amount, if any, by 

which such total SO2 emissions exceed the State assurance level as 

described in §97.706(c)(2)(iii); and

(ii) Promulgate a notice of data availability of the results of the 

calculations required in paragraph (b)(1)(i) of this section, 

including separate calculations of the SO2 emissions from each TR SO2

Group 2 source. 

(2) For each notice of data availability required in paragraph 

(b)(1)(ii) of this section and for any State (and Indian country 
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within the borders of such State) identified in such notice as having 

TR SO2 Group 2 units with total SO2 emissions exceeding the State 

assurance level for a control period in a given year, as described in 

§97.706(c)(2)(iii):

(i) By July 1 immediately after the promulgation of such notice, the 

designated representative of each TR SO2 Group 2 source in each such 

State (and Indian country within the borders of such State) shall 

submit a statement, in a format prescribed by the Administrator, 

providing for each TR SO2 Group 2 unit (if any) at the source that 

operates during, but is not allocated an amount of TR SO2 Group 2 

allowances for, such control period, the unit’s allowable SO2 emission 

rate for such control period and, if such rate is expressed in lb per 

mmBtu, the unit’s heat rate. 

(ii) By August 1 immediately after the promulgation of such notice, 

the Administrator will calculate, for each such State (and Indian 

country within the borders of such State) and such control period and 

each common designated representative for such control period for a 

group of one or more TR SO2 Group 2 sources and units in the State 

(and Indian country within the borders of such State), the common 

designated representative’s share of the total SO2 emissions from all 

TR SO2 Group 2 units at TR SO2 Group 2 sources in the State (and 

Indian country within the borders of such State), the common 

designated representative’s assurance level, and the amount (if any) 

of TR SO2 Group 2 allowances that the owners and operators of such 
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group of sources and units must hold in accordance with the 

calculation formula in §97.706(c)(2)(i) and will promulgate a notice 

of data 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)(2)(ii) of this section and the 

calculations referenced by the relevant notice of data availability 

required in paragraph (b)(1)(i) of this section. 

(A) Objections shall be submitted by the deadline specified in such 

notice and shall be limited to addressing whether the calculations 

referenced in the relevant notice required under paragraph (b)(1)(ii) 

of this section and referenced in the notice required under paragraph 

(b)(2)(ii) of this section are in accordance with §97.706(c)(2)(iii), 

§§97.706(b) and 97.730 through 97.735, the definitions of “common 

designated representative”, “common designated representative’s 

assurance level”, and “common designated representative’s share” in 

§97.702, and the calculation formula in §97.706(c)(2)(i).

(B) 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)(iii)(A) of this section. By October 1 

immediately after the promulgation of such notice, the Administrator 

will promulgate a notice of data availability of any adjustments that 

the Administrator determines to be necessary and the reasons for 
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accepting or rejecting any objections submitted in accordance with 

paragraph (b)(2)(iii)(A) of this section.

(3) For any State (and Indian country within the borders of such 

State) referenced in each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section as having TR SO2 Group 2 

units with total SO2 emissions exceeding the State assurance level for 

a control period in a given year, the Administrator will establish 

one assurance account for each set of owners and operators 

referenced, in the notice of data availability required under 

paragraph (b)(2)(iii)(B) of this section, as all of the owners and 

operators of a group of TR SO2 Group 2 sources and units in the State 

(and Indian country within the borders of such State) having a common 

designated representative for such control period and as being 

required to hold TR SO2 Group 2 allowances. 

(4)(i) As of midnight of November 1 immediately after the 

promulgation of each notice of data availability required in 

paragraph (b)(2)(iii)(B) of this section, the owners and operators 

described in paragraph (b)(3) of this section shall hold in the 

assurance account established for the them and for the appropriate TR 

SO2 Group 2 sources, TR SO2 Group 2 units, and State (and Indian 

country within the borders of such State) under paragraph (b)(3) of 

this section a total amount of TR SO2 Group 2 allowances, available 

for deduction under paragraph (a) of this section, equal to the 

amount such owners and operators are required to hold with regard to 
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such sources, units and State (and Indian country within the borders 

of such State) as calculated by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowance-holding deadline specified in 

paragraph (b)(4)(i) of this section, if November 1 is not a business 

day, then such allowance-holding deadline shall be midnight of the 

first business day thereafter.

(5) After November 1 (or the date described in paragraph (b)(4)(ii) 

of this section) immediately after the promulgation of each notice of 

data availability required in paragraph (b)(2)(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 determine whether the owners and operators 

described in paragraph (b)(3) of this section hold, in the assurance 

account for the appropriate TR SO2 Group 2 sources, TR SO2 Group 2 

units, and State (and Indian country within the borders of such 

State) established under paragraph (b)(3) of this section, the amount 

of TR SO2 Group 2 allowances available under paragraph (a) of this 

section that the owners and operators are required to hold with 

regard to such sources, units, and State (and Indian country within 

the borders of such State) as calculated by the Administrator and 

referenced in the notice required in paragraph (b)(2)(iii)(B) of this 

section.
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(6) Notwithstanding any other provision of this subpart and any 

revision, made by or submitted to the Administrator after the 

promulgation of the notice of data availability required in paragraph 

(b)(2)(iii)(B) of this section for a control period in a given year, 

of any data used in making the calculations referenced in such 

notice, the amounts of TR SO2 Group 2 allowances that the owners and 

operators are required to hold in accordance with §97.706(c)(2)(i) 

for such control period shall continue to be such amounts as 

calculated by the Administrator and referenced in such notice 

required in paragraph (b)(2)(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 and operators are 

required to hold in accordance with the calculation formula in 

§97.706(c)(2)(i) for such control period with regard to the TR SO2

Group 2 sources, TR SO2 Group 2 units, and State (and Indian country 

within the borders of such State) involved, provided that such 

litigation under part 78 of this chapter, or the proceeding under 

part 78 of this chapter that resulted in the decision appealed in 
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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)(iii)(B) of this section.

(ii) If any such data are revised by the owners and operators of a TR 

SO2 Group 2 source and TR SO2 Group 2 unit whose designated 

representative submitted such data under paragraph (b)(2)(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 and operators are required to hold in accordance with the 

calculation formula in §97.706(c)(2)(i) for such control period with 

regard to the TR SO2 Group 2 sources, TR SO2 Group 2 units, and State 

(and Indian country within the borders of such State) involved, 

provided that such litigation was initiated no later than 30 days 

after promulgation of such notice required in paragraph 

(b)(2)(iii)(B) of this section.

(iii) If the revised data are used to recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this section, the amount of TR SO2

Group 2 allowances that the owners and operators are required to hold 

for such control period with regard to the TR SO2 Group 2 sources, TR 

SO2 Group 2 units, and State (and Indian country within the borders of 

such State) involved—
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(A) Where the amount of TR SO2 Group 2 allowances that the owners and 

operators are 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 owners and operators shall hold the 

additional amount of TR SO2 Group 2 allowances in the assurance 

account established by the Administrator for the appropriate TR SO2

Group 2 sources, TR SO2 Group 2 units, and State (and Indian country 

within the borders of such State) under paragraph (b)(3) of this 

section. The owners’ and operators’ failure to hold such additional 

amount, as required, before the new deadline shall not be a violation 

of the Clean Air Act. The owners’ and operators’ 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 owners and operators fail to hold as required as of the new 

deadline, and each day in such control period, shall be a separate 

violation of the Clean Air Act. 

(B) For the owners and operators 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 all accounts 

from which TR SO2 Group 2 allowances were transferred by such owners 

and operators for such control period to the assurance account 

established by the Administrator for the appropriate at TR SO2 Group 2 

sources, TR SO2 Group 2 units, and State (and Indian country within 

the borders of such State) under paragraph (b)(3) of this section, a 
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total amount of the TR SO2 Group 2 allowances held in such assurance 

account equal to the amount of the decrease. If TR SO2 Group 2 

allowances were transferred to such assurance account from more than 

one account, the amount of TR SO2 Group 2 allowances recorded in each 

such transferor account will be in proportion to the percentage of 

the total amount of TR SO2 Group 2 allowances transferred to such

assurance account for such control period from such transferor 

account. 

(C) Each TR SO2 Group 2 allowance held under paragraph (b)(6)(iii)(A) 

of this section as a result of recalculation of requirements under 

the TR SO2 Group 2 assurance provisions for such control period must 

be a TR SO2 Group 2 allowance allocated for a control period in a year

before or the year immediately following, or in the same year as, the 

year of such control period. 

§ 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 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, or 97.728.
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§ 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 compliance account or an 

assurance 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 
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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 
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§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 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 SO2 Group 2 unit that commences 

commercial operation before July 1, 2011, 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:

(i) January 1, 2012; or

(ii) 180 calendar days after the date on which the unit commences 

commercial operation.
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(3) 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 shall meet the requirements 

of §§75.4(e)(1) through (e)(4) of this chapter, except that:

(i) Such requirements shall apply to the monitoring systems required 

under §97.730 through §97.735, rather than the monitoring systems 

required under part 75 of this chapter;

(ii) SO2 concentration, stack gas moisture content, stack gas 

volumetric flow rate, and O2 or CO2 concentration data shall be 

determined and reported, rather than the data listed in §75.4(e)(2) 

of this chapter; and

(iii) Any petition for another procedure under §75.4(e)(2) of this 

chapter shall be submitted under §97.735, rather than §75.66.

(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 
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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 to the 

atmosphere without accounting for all such SO2 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 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 
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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 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.
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(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) that is 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 
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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 
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§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 with the 

word “recertified”. 
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(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.
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(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. 
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(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 
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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.
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(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 
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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 State or 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 
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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 paragraphs (b) 

through (e) of 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 
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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; or

(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 

commence in the quarter covering January 1, 2012 through March 31, 

2012. 

(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 
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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 
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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.
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§ 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. 

(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. 
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(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.