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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-9174-9]

RIN 2060-AP50

Federal Implementation Plans to Reduce Interstate Transport of 

Fine Particulate Matter and Ozone

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. This action will 

substantially reduce adverse air 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
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NAAQS by the deadlines established in the Clean Air Act. The 

FIPs do 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 

additional upwind emission reductions and taking any necessary 

action in a future rulemaking. EPA is also issuing a 

supplemental proposal to request comment on applying ozoneseason NOX reductions in certain additional states under this 

rule.

DATES: This final rule is effective on [insert date 60 days 

after publication in the Federal Register].

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 web site. 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 
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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; e-mail 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; e-mail address rodman.sonja@epa.gov.

SUPPLEMENTARY INFORMATION:

I. Preamble Glossary of Terms and Abbreviations

The following are abbreviations of terms used in the preamble.

ARP Acid Rain Program

BART Best Available Retrofit Technology

BACT Best Available Control Technology

CAA or Act Clean Air Act

CAIR Clean Air Interstate Rule

CBI Confidential Business Information

CFR Code of Federal Regulations

EGU Electric Generating Unit

FERC Federal Energy Regulatory Commission
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FGD Flue Gas Desulfurization

FIP Federal Implementation Plan

FR Federal Register

EPA U.S. Environmental Protection Agency

GHG Greenhouse Gas

Hg Mercury

IPM Integrated Planning Model

lb/MMBtu Pounds Per Million British Thermal Unit

μg/m3 Micrograms Per Cubic Meter

NAAQS National Ambient Air Quality Standards

NOX Nitrogen Oxides

NSPS New Source Performance Standard

OTAG Ozone Transport Assessment Group

PUC Public Utility Commission

SNCR Selective Non-catalytic Reduction

SCR Selective Catalytic Reduction

SIP State Implementation Plan

PM2.5 Fine Particulate Matter, Less Than 2.5 Micrometers

PM10 Fine and Coarse Particulate Matter, Less Than 10 Micrometers

PM Particulate Matter

RIA Regulatory Impact Analysis

SO2 Sulfur Dioxide

SOX Sulfur Oxides, Including Sulfur Dioxide (SO2) and Sulfur 

Trioxide (SO3)
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TIP Tribal Implementation Plan

TPY Tons Per Year

TSD Technical Support Document

II. General Information

A. Does This Action Apply to Me?

This rule affects EGUs, and regulates the following groups:

Industry group 

NAICSa

Utilities (electric, natural 

gas, other systems.)

2211, 2212, 2213

a North American Industry Classification System.

This table is not intended to be exhaustive, but rather 

provides a guide for readers regarding entities likely to be 

regulated by this action. This table lists the types of entities 

that EPA is aware of that could potentially be regulated. Other 

types of entities not listed in the table could also be 

regulated. To determine whether your facility would be regulated 

by the proposed rule, you should carefully examine the 

applicability criteria in proposed §§ 97.404, 97.504, and 

97,604.

B. How Is The Preamble Organized?

I. Preamble Glossary of Terms and Abbreviations
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II. General Information

A. Does This Action Apply to Me?

B. How Is The Preamble Organized?

III. Executive Summary

IV. Legal Authority and Environmental Basis

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

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

C. Air Quality Modeling to Identify Downwind 

Nonattainment and Maintenance Receptors

1.Emission Inventories

2.Air Quality Basis for Identifying Receptors
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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

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

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

2.State Emission Budgets

E. Approach to Power Sector Emission Variability

1.Introduction to Power Sector Variability
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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 Limited Interstate 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

I. Permitting

1.Title V Permitting

2.New Source Review 
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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
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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 Trading 

Program Rules for Limited Interstate Trading

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 Advancement Act

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations
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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

Clean Air Act (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).
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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 Federal Implementation Plans (FIPs) to achieve the 

required emission reductions in each state through costeffective and flexible requirements for power plants. Each 

state has the option of replacing these federal rules with state 

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 
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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 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 22 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 
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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 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 

 

1 This area is not currently designated as non-attainment 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 non-attainment designation of Chicago-GaryLake 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.

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.
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(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 identifies reductions that 

are necessary but may not be sufficient to satisfy the 

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

 

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.

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 
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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 

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 promulgated, in the case of pollutants for which 

interstate transport is important, additional emission 

reductions to address transported pollution may be required from 

 

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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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 limited 

interstate trading programs with assurance provisions to ensure 

that the necessary reductions will occur within every covered 

state. The Transport Rule’s limited interstate trading approach 

will assure environmental results while providing some limited 

flexibility to covered sources. The final rule includes four 

limited interstate 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 ozone-season NOX reductions. The second phase of Transport 

Rule reductions commences January 1, 2014. 

EPA projects that with the Transport Rule, covered electric 

generating units (EGU) will substantially reduce SO2, annual NOX

and ozone-season NOX emissions, as shown in Tables III-2 and III-
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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. 

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 reductions 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, 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 
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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 analysis to determine whether a state’s 
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contribution to downwind air quality problems is above specific 

thresholds. A state is covered by the Transport Rule if it 

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

When EPA proposed this air-quality and cost-based multifactor 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 Transport Rule's approach of using air-quality 

thresholds to determine upwind-to-downwind-state linkages and 

 

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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using the cost- and air quality-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 obligations pursuant 

to section 110(a)(2)(D)(i)(I), this approach addresses the 

Court’s concerns about the development of CAIR budgets. 
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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 

 

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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variability limits which extend above the state budgets to form 

each state’s “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 reductions 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 
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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 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 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 limited interstate trading programs. As 

discussed in section IX below, EPA is creating these Transport 

Rule allowances as distinct compliance instruments with no 

relation to allowances from the CAIR trading programs. EPA 

recognizes the administrative value of continuity under 

successive regulatory trading programs; however, EPA is 

promulgating the Transport Rule as a Court-ordered replacement 

for (not a successor to) CAIR’s trading programs. EPA will 

strongly consider administrative continuity of this rule’s 
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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 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 stringency than “Group 2” states. 

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 1997 2006 24- SO2

 

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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NAAQS Annual 

PM2.5 NAAQS

Hour PM2.5

NAAQS

Group

Alabama X X X 2

Arkansas X

Florida X

Georgia X X X 2

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 X 2

Virginia X X 1

West Virginia X X X 1
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Wisconsin X X 1

Number of States 20 18 22

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 states with contributions to certain downwind receptors 

that 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 

 

9 EPA updated its modeling platforms and modeling inputs in 

response to public comments received on the proposed Transport 

Rule and subsequent Notices of Data Availability and performed 

other standard updates.
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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, and the District of Columbia 

significantly contributed to nonattainment or interference 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, 
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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 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 
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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. With respect to the annual PM2.5 NAAQS, in the proposal EPA 

requested comment on whether Texas should be included but did 

not propose specific SO2 and NOX emission budgets for that state. 

The modeling conducted for the final rule supports EPA’s 

conclusion that Texas does significantly contribute to 

nonattainment or interfere with maintenance of the annual NAAQS 

in another state. EPA provided a full opportunity for comment 

on whether Texas should be included in the rule for PM2.5, and 

therefore EPA is finalizing annual SO2 and NOX emission budgets 

for Texas in this rule. 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 
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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 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 
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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 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

2012 

Transport 

2012

Emission 

2014

Base Case 

2014 

Transport 

2014

Emission 
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Emissions Rule 

Emissions

Reductions Emissions Rule 

Emissions

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.

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

(Million Tons)

2005 Actual 

Emissions

2012 

Transport 

Rule

Emissions

2012

Emissions

Reductions 

from 2005

2014 

Transport 

Rule

Emissions

2014

Emissions

Reductions 

from 2005

SO2 8.8 3.0 5.8 2.4 6.4

Annual 

NOX

2.6 1.3 1.3 1.2 1.4
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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 covered states (including 

the six states for which EPA issued a supplemental proposal for 

ozone-season NOX requirements) in 2014.
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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

Social costs

3 % discount rate $0.81

7 % discount rate $0.81

Total monetized benefitsb

3 % discount rate $120 to $280
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7 % discount rate $110 to $250

Net benefits (benefits-costs)

3 % discount rate

7 % discount rate

$120 to $280

$100 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.

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.

 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 and VI.

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

state assurance levels, based on updated modeling. See

section VI.
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 Simplified variability limits for one-year application only 

and adjusted calculations to improve alignment with each 

state’s historic variability. See section VI.

 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. See section VII.

 Changed start of assurance provisions to 2012 and increased 

assurance provision penalties. See section VII.

 Removed opt-in provisions. See section VII.

 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 
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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 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 
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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, costeffective and flexible greenhouse gas (GHG) emissions 

performance standards under section 111 for steam electric 

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.
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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 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 emissions 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 

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 and Environmental Basis

A. EPA’s Authority for Transport Rule

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

“good neighbor” provision of the Act, requires states to 

prohibit certain emissions because of their impact on air 
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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 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 the section, EPA has authority to 

clarify the applicability of CAA requirements. In this action, 

among other things, EPA is clarifying the applicability of 
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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. In addition, section 110(k)(1)(A) 

calls for the Administrator to establish criteria for 

determining whether SIP submissions are complete. 42 U.S.C. 

sec. 7410(k)(1)(A). Among other things, this action helps to 

clarify what SIP submissions must contain to address the 

requirements of section 110(a)(2)(D)(i).

Section 110(c)(1) of the Act, also requires EPA to act in 

certain circumstances where state SIP deficiencies exist, 

regardless of the reason for the deficiency. EPA action may be 

required even if the SIP deficiency is not in any way the fault 

of the affected state, for example, if the deficiency is caused 

by factors beyond the state’s control. Specifically, 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. sec. 7410(c)(1).

B. Rulemaking History
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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 achieved CAIR’s 

emission reductions requirements unless or until states had 

approved SIPs to achieve the required reductions.

 

10 As discussed in section III of this preamble, simultaneous 

with this final rule, 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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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 

emissions 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 
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reductions under FIPs, which states may choose to replace by 

submitting SIPs for EPA approval. EPA proposed to limit 

emissions by regulating electric generating units in the 32 

states with limited interstate emissions 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 Notices of Data 

Availability (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 unitlevel 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 
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and 2014 for several stationary and mobile source inventory 

components.

 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
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Fine particles are associated with a number of serious 

health effects including premature mortality, aggravation of 

respiratory and cardiovascular disease (as indicated by 

increased hospital admissions, emergency room visits, healthrelated absences from school or work, and restricted activity 

days), lung disease, decreased lung function, asthma attacks, 

and certain cardiovascular problems. 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. 
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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, shortterm exposure to ozone can irritate the respiratory system, 

causing coughing, throat irritation, and chest pain. Ozone can 

reduce lung function and make it more difficult to breathe 

deeply. Breathing may become more rapid and shallow than 

normal, thereby limiting a person’s normal activity. Ozone also 

can aggravate asthma, leading to more asthma attacks that may 

require a doctor’s attention and the use of additional 

medication. Increased hospital admissions and emergency room 

visits for respiratory problems have been associated with 

ambient ozone exposures. Longer-term ozone exposure can inflame 

and damage the lining of the lungs, which may lead to permanent 

changes in lung tissue and irreversible reductions in lung 

function. A lower quality of life may result if the 

inflammation occurs repeatedly over a long time period (such as 

months, years, or a lifetime). There is also 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 
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and survivability of tree seedlings; and increased plant 

susceptibility to disease, pests, and other environmental 

stresses (e.g., harsh weather). In long-lived species, these 

effects may become evident only after several years or even 

decades and have the potential for long-term adverse impacts on 

forest ecosystems. Ozone damage to the foliage of trees and 

other plants can also decrease the aesthetic value of ornamental 

species used in residential landscaping, as well as the natural 

beauty of our national parks and recreation areas. In 1997, at 

the same time we revised the PM2.5 standards, EPA issued its 

final action to revise the NAAQS for ozone (62 FR 38856) to 

establish new 8–hour standards. In this action published on 

July 18, 1997, we promulgated identical revised primary and 

secondary ozone standards that specified an 8-hour ozone 

standard of 0.08 parts per million (ppm). Specifically, the 

standards require that the 3-year average of the fourth highest 

24-hour maximum 8-hour average ozone concentration may not 

exceed 0.08 ppm. In general, the 8-hour standards are more 

protective of public health and the environment and more 

stringent than the pre-existing 1-hour ozone standards.

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 
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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.

For this proposal, 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.
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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 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 
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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

This section explains EPA’s legal responsibility and 

authority to impose FIPs under this final rule. As noted above, 

section 110(c)(1) of the Act requires EPA to act in certain 
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circumstances where state SIPs are deficient. Specifically, 

section 110(c)(1) requires the Administrator to promulgate a 

Federal Implementation Plan (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 with respect to a specific 

NAAQS, she has a legal obligation to promulgate a FIP within two 

years. That obligation can only be discharged by promulgating a 

FIP unless 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). 

As explained in the proposal (75 FR 45218, 45226, 45285 and 

45341), all states have an obligation to submit SIPs that 

address the requirements of CAA section 110(a)(2), including 

110(a)(2)(D)(i)(I) within 3 years of promulgation or revision of 

a NAAQS. For all of the states covered by this rule, EPA has 

either found that the state has failed to make a required 

110(a)(2)(D)(i)(I) SIP submission, issued a SIP Call, or 

disapproved a SIP submission. In addition, EPA has determined 

that there has been no approval by the Administrator of a SIP 
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submission correcting the deficiency prior to promulgation of 

this FIP. The specific findings made and actions taken by EPA 

are described in greater detail in the TSD entitled “Status of 

110(a)(2)(D)(i)(I) SIPs.” 

 In 2005, EPA found that all states had failed to make 

submissions that address the requirements of section 

110(a)(2)(D)(i) related to interstate transport of pollution 

with respect to the 1997 ozone and 1997 PM2.5 NAAQS. See 70 FR 

21147 (April 25, 2005). Also in 2005, EPA promulgated CAIR, 

which was intended to provide states covered by the rule with a 

mechanism to satisfy their section 110(a)(2)(D)(i)(I) 

obligations. In CAIR, EPA concluded that the states in the CAIR 

region would meet their section 110(a)(2)(D)(i) obligations to 

address “significant contribution” and “interference with 

maintenance” requirements by complying with CAIR requirements.

 Consequently, states within the CAIR region did not need to 

submit a separate SIP revision to satisfy the section 

110(a)(2)(D)(i) requirements provided they submitted a SIP 

revision to satisfy CAIR. Most CAIR states participated in the 

CAIR trading programs and submitted SIP revisions that EPA 

subsequently approved. Subsequent to those SIP approvals, CAIR 

was found unlawful and remanded to EPA. Among other things, the 

Court found that CAIR did not effectuate the statutory mandate 

of section 110(a)(2)(D)(i)(I). Because the court found CAIR and 
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the CAIR FIPs unlawful, and because it held that the emission 

reduction requirements in CAIR were not tied to the requirements 

of 110(a)(2)(D)(i)(I), compliance by a state with CAIR could not 

be said to satisfy its 110(a)(2)(D)(i)(I) obligations with 

respect to the 1997 ozone or 1997 PM2.5 NAAQS. In other words, a 

CAIR SIP submission cannot be found to correct a state’s 

110(a)(2)(D)(i)(I) deficiency. Therefore, the deficiency 

remains, not because the state failed to comply with CAIR, but 

because the Court found that CAIR did not address the 

110(a)(2)(D)(i)(I) statutory mandate and thus did not correct 

any 110(a)(2)(D)(i)(I) deficiencies. For this reason, submittal 

and approval of the CAIR SIPs did not relieve EPA of its 

obligation, under CAA section 110(c)(1) to promulgate FIPs to 

cure the deficiencies identified in the 2005 findings of failure 

to submit.11

The 2005 findings of failure to submit also remain in force 

for many states not covered by the original CAIR. As explained 

above and in the Transport Rule proposal (75 FR 45342), EPA has 

an obligation and authority to promulgate a FIP for any state 

covered by those findings unless “the State corrects the 

 

11 The 2005 findings of failure to submit related to state’s 

obligations pursuant to section 110(a)(2)(D)(i). CAIR, however, 

addressed only the requirements of 110(a)(2)(D)(i)(I). The 

remand of CAIR, therefore, had no impact on state SIP 

submissions or EPA approval of state SIP submissions pursuant to 

section 110(a)(2)(D)(i)(II).
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deficiency, and the Administrator approves the plan or plan 

revision, before the Administrator promulgates such Federal 

implementation plan.” 42 U.S.C. sec. 7410(c)(1). Thus, EPA has 

an obligation to promulgate FIPs for states covered by the 2005 

findings that have either not yet submitted 110(a)(2)(D)(i)(I) 

SIPs with respect to the 1997 ozone and 1997 PM2.5 NAAQS or that 

have not received EPA approval of SIP submittals that correct 

the deficiency. The plain language of 110(c)(1) states that 

EPA’s FIP obligation is not discharged unless the state corrects 

the deficiency and the Administrator approves the plan or plan 

revision before promulgation of a FIP. 42 U.S.C. sec. 7410. EPA 

recognizes its obligations under the statute. It has also made 

every effort to act on all 110(a)(2)(D)(i)(I) SIP submissions 

received for states covered by the Transport Rule prior to 

promulgation of this rule.

In addition, many states that submitted SIPs to address the 

110(a)(2)(D)(i)(I) obligation for the 2006 PM2.5 standard relied 

on CAIR for all or a portion of their submittal. EPA has 

disapproved all such SIPs as CAIR did not purport to address the 

requirements of 110(a)(2)(D)(i)(I) with respect to the 2006 PM2.5

NAAQS. EPA approved the 110(a)(2)(D)(i) submission from the 

state of Kansas for the 1997 ozone and 1997 PM2.5 NAAQS on March 

9, 2007 (72 FR 10608). The modeling done for the proposed 

Transport Rule, however, demonstrated that emissions from Kansas 
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significantly contribute to nonattainment or interfere with 

maintenance of the 1997 8-hour ozone NAAQS in other states. 

Because the SIP approved for Kansas did not prohibit these 

emissions, EPA determined that it was not adequate to satisfy 

the requirements of 110(a)(2)(D)(i)(I). Therefore, EPA proposed 

a SIP Call under CAA 110(k)(5) for Kansas (76 FR 763, January 6, 

2011), finding the state’s existing SIP substantially inadequate 

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

the 1997 ozone NAAQS. In the proposal, EPA would allow Kansas 

18 months to submit a SIP to correct the deficiency. 

Alternatively, Kansas could ask EPA to impose a FIP beginning in 

the 2012 ozone-season. Any final action regarding that SIP call 

will be taken under a separate action, and will establish a 

deadline for submission of a new 110(a)(2)(D)(i)(I) SIP which 

EPA would review for completeness.12

Additionally, EPA has acted to disapprove several SIPs that 

EPA concluded were not adequate to address CAA section 

110(a)(2)(D)(i)(I) for the 2006 PM2.5 NAAQS, or is acting to 

disapprove such SIPs simultaneously with this action. 

 

12 EPA is neither finalizing a FIP for Kansas with respect to the 

1997 ozone NAAQS nor finalizing a NOX ozone season budget for 

Kansas in this rule. For reasons explained therein, EPA is 

issuing a supplemental notice of proposed rulemaking to provide 

an opportunity for public comment on our conclusion that Kansas 

significantly contributes to nonattainment or interferes with 

maintenance of the 1997 ozone NAAQS.
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EPA recognizes that many of these 110(a)(2)(D)(i)(I) SIP 

submittals took place in advance of EPA’s development of the 

Transport Rule, which clarifies certain states’ responsibilities 

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

1997 PM2.5 and 2006 PM2.5 NAAQS. For the states that have now been 

identified to be contributing significantly to nonattainment or 

interfering with maintenance under this rule, EPA cannot approve 

a 110(a)(2)(D)(i)(I) SIP that does not achieve the reductions 

EPA has determined are required by section 110(a)(2)(D)(i)(I). 

For this reason, EPA is disapproving simultaneously with this 

rule a SIP for the State of Texas that was pending before the 

action, but has now for the reasons explained above been 

identified as inadequate. 

For states that did not submit transport SIPs for the 2006 

PM2.5 NAAQS, as noted in the Transport Rule proposal, EPA issued 

a notice finding that a number of states failed to make the 

required 110(a)(2)(D)(i)(I) SIP submissions. See 75 FR 32673, 

June 9, 2010. EPA issued a second notice finding that 

additional states had failed to make required 110(a)(2)(D)(i)(I) 

SIP submissions with respect to the 2006 PM2.5 NAAQS. [PLACEHOLDER 

FOR FEDERAL REGISTER PUBLICATION OF THIS FINDING AHEAD OF 

TRANSPORT RULE]. 

Responses to Comments
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Many commenters argued that the Transport Rule should not 

include FIPs and that EPA lacked authority to issue FIPs at this 

time. 

Because EPA’s legal obligation and authority to issue a FIP 

arises from a determination that an individual state SIP 

contains a deficiency that has not been corrected, questions 

regarding whether EPA has authority to issue a FIP are state 

specific. In this action, EPA is issuing 60 FIPs. EPA is 

issuing FIPs to 20 states to correct SIP deficiencies relating 

to the 110(a)(2)(D)(i)(I) requirements for the 1997 ozone NAAQS. 

EPA is also issuing FIPs to 18 states to correct SIP 

deficiencies relating to the 1997 PM2.5 NAAQS. Finally, EPA is 

issuing FIPs to 22 states to correct SIP deficiencies relating 

to the 2006 PM2.5 NAAQS. In each case, EPA both has determined 

either through a finding of failure to submit, a SIP Call, or a 

disapproval of a SIP submission that the state SIP is deficient 

because it does not include provisions adequate to prohibit 

emissions within the state that significantly contribute to 

nonattainment or interfere with maintenance with respect to the 

relevant NAAQS and determined that subsequent to such a 

determination there has been no EPA approval of a SIP that cures 

the deficiency. The TSD entitled “Status of 110(a)(2)(D)(i)(I) 

SIPs” identifies each action taken by EPA with respect to the 

110(a)(2)(D)(i)(I) SIP requirements for the states covered by 
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the Transport Rule, with respect to the NAAQS for which those 

states are covered. This TSD demonstrates that for each FIP 

promulgated in this rule, EPA has both authority and a legal 

obligation to promulgate a FIP to correct the identified SIP 

deficiency.

Some commenters 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. 

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 that EPA is obligated to remedy those flaws. 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 
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believe it would be appropriate to establish a lengthy 

transition period to the rule which is to replace CAIR.

Many commenters also observed that states do not have 

enough time to submit a SIP between the time the Transport Rule 

is finalized and the start of its requirements and argued that 

EPA should restart the “FIP clock.”13 EPA does not interpret the 

Clean Air Act as giving it authority to restart the FIP clock. 

The language of section 110(c)(1) of the Act provides that EPA 

shall promulgate a FIP within 2 years after the Administrator 

finds that a state has failed to make a required submission or 

after disapproving a state implementation plan submission in 

whole or part, unless the state corrects the deficiency, and the 

Administrator approves the plan or plan revision, before the 

promulgation of a FIP. See 42 U.S.C. sec. 7410(c)(1).

Some also objected to EPA imposing FIPs for the 2006 PM2.5

NAAQS prior to the expiration of the FIP clock for that 

standard.

CAA Section 110(c)(1) requires EPA to promulgate a FIP “at 

any time within 2 years” after a finding of failure notice or a 

SIP disapproval. EPA is promulgating the necessary FIPs with 

 

13 “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; that a submitted SIP revision is found 

incomplete; or EPA has disapproved a SIP revision.
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regard to the 2006 PM2.5 NAAQS in this final action within the 

statutory timeframe.

There were also commenters that supported the approach 

proposed by EPA to replace CAIR and achieve the necessary 

reductions as quickly as possible. EPA agrees it is important 

to achieve the reductions quickly.

Regarding the 1997 NAAQS specifically, commenters felt the 

approved CAIR SIPs satisfied the 110(a)(2)(D)(i)(I) requirements 

and that those SIPs should be acted on in order for EPA to have 

authority to impose FIPs for those NAAQS. 

EPA has considered all comments and believes that it would 

be inconsistent with opinion of the Court in North Carolina to 

find that compliance with the requirements of CAIR satisfies the 

requirements of 110(a)(2)(D)(i)(I) for the 1997 ozone NAAQS and 

1997 PM2.5 NAAQS. Among other things, the Court concluded that 

CAIR did not identify each upwind state’s significant 

contribution or demonstrate that the rule achieved “something 

measurable 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 at 

907-08. It would be inconsistent with this strong language for 

EPA to determine that a CAIR SIP submission that relied on CAIR 

or the CAIR modeling, satisfies the requirements of 

110(a)(2)(D)(i)(I). EPA fully acknowledges that the CAIR SIPs 
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were submitted in good faith and based on EPA’s determination in 

the CAIR rule that compliance with CAIR would satisfy the 

requirements of 110(a)(2)(D)(i)(I). That determination, 

however, was overturned by the Court, and EPA is bound by the 

Court’s interpretation of Clean Air Act requirements. Thus, the 

CAIR SIPs, even though they were approved by EPA, do not correct 

the SIP deficiency identified in the findings. Therefore, the 

2005 findings remain in force and EPA continues to have both the 

obligation and authority to promulgate the FIPs for the 1997 

standards finalized in this action.14,15

3. Additional Information Regarding CAA Section 

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

Modeling Domain

This final rule evaluates and finds out-of-state 

contributions for the 38 states that are fully contained within 

the 12 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 

 

14 The “FIP clock” for the 2005 findings notice expired June 9, 

2007.

15 See TSD entitled “Status of 110(a)(2)(D)(i)(I) SIPs.”
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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 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 upwind of 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 

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 current SIP (for those states that 

have already submitted SIPs to address 110(a)(2)(D)(i)(I)

requirements) is adequate to address the transport requirements 

of 110(a)(2)(D)(i)(I). Additionally, if a state has never 

submitted an interstate transport SIP and intends to submit a 

SIP, the state can rely on the technical analysis in this rule 

for its SIP submission. For example, this rule finds that South 

Carolina significantly contributes to nonattainment and 
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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.

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 proposal 

discusses the pollutants regulated under the final Transport 

Rule.

1. Background.

Based on the understanding of scientific and technical 

information, as well as EPA’s air quality modeling, EPA 

concluded for CAIR that it was both appropriate and necessary to 

focus on control of SO2 and NOX emissions as the most effective 

approach to reducing the contribution of interstate transport to 

PM2.5. For CAIR, EPA did not include emissions limitations that 
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affect other components of PM2.5, noting that “current 

information relating to sources and controls for other 

components identified in transported PM2.5 (carbonaceous 

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

time, provide an adequate basis for regulating the regional 

transport of emissions responsible for these PM2.5 components” 

(69 FR 4582). 

With respect to ozone transport, EPA has previously 

concluded that it is proper to focus on ozone-season NOX

emissions. For the CAIR and the NOX SIP call programs, EPA noted 

its reliance on the assessment of ozone transport made 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 and that benefits grew 

with increased 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 
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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 manmade 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 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 Web 
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site at: http://www.epa.gov/airmarkets/ progress/progressreports.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 addressed NOX emissions but did not 

include requirements for VOCs. EPA believes that VOCs from some 

upwind states do indeed have an impact in some nearby downwind 

states, particularly over short transport distances. 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 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 continue to focus the PM2.5
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transport requirements on SO2 and NOX emissions and to focus the 

ozone transport requirements on NOX emissions. 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 ozone-season 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 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 PM contribution 

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

especially pertinent concern for southern states which have 

significant impacts on northern receptors in colder climates 

where nitrate concentrations are generally higher. For example, 

 

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 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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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 made 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 for states 

affecting downwind state PM2.5 nonattainment and maintenance 

sites.

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. 

EPA notes that for the final rule this issue has become moot for 

two states -- Florida and Louisiana. For those two states, the 

modeling analysis for the final rule showed their overall 

contributions to PM2.5 at downwind receptors of concern are below 

the threshold for inclusion. Accordingly, Florida and Louisiana 
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are no longer covered by the Transport Rule for PM2.5 and thus 

are no longer included in the annual NOX program.

B. Baseline for Pollution Transport Analysis

Implementing the requirements 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 National Ambient Air Quality Standards 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 beyond those already mandated by 

existing emission limitation requirements are necessary. 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 
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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 ignore that capital investments have already been made to 

meet the requirements of CAIR and that these investments 

comprise “sunk” capital costs and not new costs, EPA’s analysis 

would not correctly 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 28 states and the District of Columbia to 

make phase I emission reductions in NOX emissions starting in 

2009, phase I emission reductions in SO2 starting in 2010, and 

additional, 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 
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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 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 is to 

replace CAIR. Thus, the Transport Rule itself will be 

terminated by emission limitations established in CAIR. 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 
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the like that establish permanent emission limitations. EPA 

takes reductions made to comply with permanent limits 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 the 

effect of the Transport Rule as a replacement for CAIR 

distinguish the emission reductions required by CAIR from those 

of other regulatory requirements. Since the limits and emission 

reduction requirements in CAIR are temporary and will be 

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

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 
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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 

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 
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of excluding sources in a state from the Transport Rule because 

of their CAIR–required emission reductions while simultaneously 

eliminating those CAIR-required emission reductions. 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 have increased 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 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 
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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 2012 base case. Commenters’ claims that, 

in excluding CAIR-specific 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, are incorrect. As discussed elsewhere in 

this preamble, EPA accounted for any Title V permits, consent 

decrees, state rules, and the like that required specific 

sources to limit their emissions to the levels consistent with 
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CAIR compliance. 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 

dismantled, and as discussed elsewhere in this preamble, EPA’s 

analysis properly treats the capital investments made in 

emission controls as a result of CAIR as “sunk” capital costs 

(i.e., capital costs already incurred in the past) that are not 

included as costs of meeting Transport Rule requirements.

Our cost analysis for significant contribution reflects onthe-ground realities. Investments in pollution control 

equipment were made in response to the remanded CAIR 

requirements. Those expenditures are “sunk” capital costs, 

meaning that those costs were incurred in the past, prior to the 

Transport Rule. Adding the capital costs of that equipment into 

the costs of Transport Rule emission reduction options 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 
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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

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. 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 

 

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 

atwww.epa.gov/airmarkets/progsregs/epa-ipm/IPM_Update_Documentation.pdf).
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emission inventories because emissions from multiple source 

categories are needed for the model to compute values for the 

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 is provided in the 

Emission Inventory Technical Support Document (TSD) for the 

Transport Rule Notice of Final Rulemaking (NFR). Tables that 

provide summaries of SO2 and NOX emissions by state and sector 

for 2005, 2012, and 2014 are also available in the Emission 

Inventory TSD.

On October 27, 2010 a Notice of Data Availability (NODA) on 

“Revisions to Emission Inventories” was issued. The primary 

purpose was to notify the public about changes to emission 

inventories made since the proposal modeling. The affected 

emission sectors were stationary point sources that are not 
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EGUs, nonpoint sources, and Category 3 commercial marine vessel 

sources. Plans to use a newly released model for onroad mobile 

source emissions were also announced in the NODA. 

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 emissions 

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 

provide 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 
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modeled for 2012 and 2014 represent predicted emission 

reductions primarily from already promulgated federal measures. 

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 futureyear cases. EPA made this conservative assumption because it 

does not currently have data to support projections of futureyear 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 EPA’s Clean Air Markets 

Division’s Continuous Emissions Monitoring (CEM) program, with 

other EGU pollutants estimated using emission factors and the 

annual heat input data reported to EPA’s Clean Air Markets 

Division. Although only the pollutants NOX and SO2 are 

considered for control in this rule, emissions for all criteria 

air pollutants must be provided to the air quality model. For 

EGUs without CEMs, data submitted to the NEI by the states were

used. For more information on the details of how the 2005 EGU 

emissions were developed, see the Emissions Inventory TSD. A 

comment impacting the final 2005 EGU inventory is the following:
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Comment: 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.

Response: EPA reviewed the assignment of EGUs and non-EGUs 

and reclassified EGU sources found to be in the non-EGU 

inventory into the 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 Inventory 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 Rulerelated 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 
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(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 section

V.C.2.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 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
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Details on the development of emission inventories are 

available in the Emission Inventory 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 for the PM NAAQS rule 

(http://www.epa.gov/ttn/ecas/regdata/RIAs/Appendix%20D--

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 
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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 nonEGU 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 futureyear 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 closures, consent decrees, emission 

caps, control programs, enforceable local controls, and 

alternative emission estimates.
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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 

sector-specific modeling results.

Comment: EPA specifically requested comments on whether to 

incorporate emission reduction estimates from the National 

Emissions Standards for Hazardous Air Pollutants (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 
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reductions from this rule would 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 

state-month level emissions for all criteria pollutants and all 

modes (exaporative, 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 
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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 pollutant had not been provided. 

Additional information on the approach to onroad mobile source 

emissions is available in the Emission Inventory 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 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 
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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.

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 
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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 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 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 
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Rule modeling, EPA updated the nonpoint emission estimates for 

oil and gas sources. EPA continued to use the same WRAP 

inventory from the proposal, but for the final modeling 

emissions in Texas and Oklahoma were updated 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.

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. 
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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 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 
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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 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 
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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 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. 
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To support the proposal, air quality modeling was performed 

for four emissions scenarios: a 2005 base year, a 2012 “no CAIR” 

base case, a 2014 “no CAIR” base case, and a 2014 control case 

that reflects the 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 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 2003-2007 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 

 

18 Comprehensive Air Quality Model with Extensions Version 5 

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

March 2009.
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applications were designed to cover states in the central and 

eastern U.S. using a horizontal resolution of 12 x 12 km19. 

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. 

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 

 

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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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.2. 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 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 
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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 

Technical Support Document. 

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 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, 
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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 five 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 

(five 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.

After 2005, early emission reductions of SO2 and NOX in 

anticipation of 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 

 

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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future year. The early years of the five year period (2003, 

2004, and 2005) were not impacted by CAIR21. The last two 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 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 nonEGU emission reductions due to existing rules or the 

 

21 The CAIR final rule was published on May 12, 2005.
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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 the Integrated Planning Model (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 

emissions changes based on comments to the proposed rule and a 

subsequent emission inventory notice of data availability 

(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 solely on modeled 

violations. They also say that we if we had looked at the most 
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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 use no-CAIR base case modeling. 

It is simply not appropriate to examine the current monitoring 

data, which represent air quality with CAIR emission reductions 
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in place, and compare the values to 2012 projected air 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 emissions 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 
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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 

receptors should not be nonattainment receptors (which we do not 

agree with), the same argument cannot be made with regards to 

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. 
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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 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 

Transport Rule states, there were 158 ozone monitor days that 

 

22 The 2010 data is preliminary. Exceptional event data has not 

been flagged and removed from the reported data. 
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exceeded 84 ppb in 2009 compared to 412 monitor days in 2010. 

For PM2.5, there were 251 monitor days that exceeded 35 μg/m3 in 

2009 compared to 417 monitor 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 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. 

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 the CAIR). Therefore, the starting point 

design values used to project to the future should not be 

lowered to account for emissions reductions trends that occur 

after 2005. Doing so would give “double credit” to the more 

recent emissions reductions and provides an inappropriate 

downward adjustment to the early design value periods of the 

2003-2007 period.
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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 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 
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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 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.
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Comment: One commenter 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. 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 

Clean Air Act. 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 
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Page 112 of 1339

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 noCAIR 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 

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 
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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 

comments23. 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 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 

 

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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Page 114 of 1339

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 98th percentile day is the 3rd high day for 

the year, this assumes 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 

lowering the future year 24-hour design values compared to the 
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Page 115 of 1339

old methodology. The 2012 base case design values for all 

nonattainment and maintenance receptors were either unchanged or 

lower with the revised methodology. 

2. 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 data24. The methodology to identify maintenance 

receptors is also unchanged from the proposal. We continue to 

use the maximum design value (from the five 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 

 

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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air quality standard over time. The way that EPA defined 

maintenance based on year-to-year 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 emissions reductions from this proposed rule, no 

further reductions are required solely for this purpose at PM 

and ozone receptors for which we are partially or fully 

determining significant contribution for the current NAAQS. (See 

discussion of emissions trends in Chapter 7 of TSD entitled 

‘‘Emission Inventories,’’ included in the docket for 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 
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Page 117 of 1339

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 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

 

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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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 three future-year PM2.5

design values for each receptor. We used the highest of these 

projections at each receptor to determine which sites are 

expected to have maintenance problems in 2012. We used the five 

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 

NAAQS27.

 

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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Page 119 of 1339

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 

receptor methodology can be found in the Air Quality Modeling 

Technical Support Document.

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 place28. 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/m3 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 

 

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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Page 120 of 1339

the maximum design value is always greater than or equal to the 

5-year weighted average. For ease of reference we use the term 

“nonattainment sites” to refer to those sites that are projected 

to exceed the NAAQS based on both the average and maximum design 

values. Those sites that are projected to be attainment based 

on the average design value but exceed the NAAQS based on the 

maximum design value are referred to as maintenance sites. The 

monitoring sites that we project to be nonattainment and/or 

maintenance for the annual PM2.5 NAAQS in the 2012 base case are 

the nonattainment/maintenance receptors used for assessing the 

contribution of emissions in upwind states to downwind 

nonattainment and maintenance of the annual PM2.5 NAAQS.

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
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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

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
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The procedures for calculating the future year 24-hour PM2.5

design values have been updated for the final rule29. 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 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 98thpercentile day could only be displaced “from below” in the 

instance that a different day’s future concentration exceeded 

the original 98th-percentile day’s future concentration. In 

 

29 There were no updates to the ozone and annual PM2.5 attainment 

test methodology.
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that case, the original 98th-percentile day may become the 97thor 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 at 

receptors 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 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 
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Page 124 of 1339

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 Technical 

Support Document. 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 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 
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Page 125 of 1339

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
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180970081 Indiana Marion 38.2 39.2 35.8 36.9

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
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170316005 Illinois Cook 39.1 41.8 34.1 36.4

171190023 Illinois Madison 37.3 38.1 35.1 35.8

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 
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ozone calculations. Additional details are provided in the Air 

Quality Modeling Technical Support Document.

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 ppb30.

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 

 

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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future year maintenance sites. Note that, as described 

previously for the annual and 24-hour PM2.5 NAAQS, nonattainment 

sites for the ozone NAAQS are also maintenance sites because the 

maximum design value is always greater than or equal to the 5-

year weighted average. 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
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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 

Design

Value 

2003-2007

Maximum 

Design 

Value 

2003-2007

Average 

Design 

Value 

2012

Maximum 

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 
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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 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 threshold 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 
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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.

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. 
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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 TSD). In this analysis, 

EPA identifies for annual PM2.5 (sulfate and nitrate), 24-hour 

PM2.5 (sulfate and 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 
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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 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 
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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, 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 
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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 for the final CAIR, there 

would be no air quality threshold for 24-hour PM2.5, which EPA 
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believes to be counter-intuitive and unworkable as an approach 

for assessing interstate contributions.

Therefore, for this rule, EPA proposed and is now 

finalizing a 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 two-digit thresholds for both annual PM2.5 and 24-hour 
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PM2.5 in the final rule is both reasonable and appropriate. The 

departure from the 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 
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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 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 

because 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 
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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 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 Technical Support Document. 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 multiplefactor 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 multifactor 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 shortterm high PM2.5 episodic conditions.
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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 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 
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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 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 
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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-of-the 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. 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 

receptor location in the modeling domain is tracked back to 

specific sources of emissions and boundary conditions to fully 
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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.2 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, Kentucky, Louisiana, Maine, Maryland31, 

 

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 
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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.1. 

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 uncertainty. There were no comments that 

suggested an alternative approach.

 

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. 
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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 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.
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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 attainment 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 Technical Support Document. The 

largest contribution from each state to annual PM2.5

nonattainment in downwind sites is provided in Table V.D-1. The 

largest contribution from each state to annual PM2.5 maintenance 

in downwind sites is also provided in Table V.D-1. The 
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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 Technical Support 

Document.

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
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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)

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

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 

 

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.
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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.D-3, we provide a list of the downwind maintenance sites to 

which each upwind state contributes 0.15 μg/m3 or more (i.e., the 

upwind state to downwind maintenance “linkages”). 

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)
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Upwind State Downwind Receptor Sites

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)

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)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 152 of 1339

Upwind State Downwind Receptor Sites

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)

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)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 153 of 1339

Upwind State Downwind Receptor Sites

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 Technical Support Document. 

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 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 Technical Support 

Document.

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
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 154 of 1339

Upwind State Largest Downwind

Contribution to 

Largest Downwind 

Contribution to 

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

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
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 155 of 1339

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, 

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”). 

 

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.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 156 of 1339

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)

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)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 157 of 1339

Upwind State Downwind Receptor Sites

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)

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)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 158 of 1339

Upwind State Downwind Receptor Sites

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)

Wisconsin

Cook, IL 

(170311016)

Wayne, MI 

(261630019)

Wayne, MI 

(261630033)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 159 of 1339

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)

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)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 160 of 1339

Upwind State Downwind Receptor Sites

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)

Nebraska

Milwaukee, WI 

(550790010)

Milwaukee, WI 

(550790026)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 161 of 1339

Upwind State Downwind Receptor Sites

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***

Page 162 of 1339

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 635 sites that are projected to have maintenance 

problems for the 8-hour ozone NAAQS in the 2012 base case. A 

 

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.
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detailed description of the calculations can be found in the Air 

Quality Modeling Technical Support Document (AQMTSD). The 

largest contribution from each state to 8-hour ozone 

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 AQMTSD. 

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
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Upwind State

Largest Downwind

Contribution to 

Largest Downwind 

Contribution to 

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

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. 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”).
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There are 26 states36 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. 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)

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)

 

36 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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Upwind State Downwind Receptor Sites

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)

Kansas

Allegan, MI 

(260050003)
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Upwind State Downwind Receptor Sites

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)

VI. Quantification of State Emission Reductions Required
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A. Cost and Air Quality Structure for Defining Reductions

1. Summary

Section V, above, describes EPA’s approach to identifying

upwind states that 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 it exceeds one of those air 

quality thresholds and the Agency identifies, using the costand 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 PM2.5or 2006 PM2.5 NAAQS.

In this section, EPA explains its final cost- and air 

quality-based 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 

today’s notice: the 1997 ozone NAAQS, the 1997 annual PM2.5 NAAQS 

and the 2006 24-hour PM2.5 NAAQS. EPA believes that the 

methodology finalized today 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 
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maintenance with 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 
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reductions that are necessary but may not be sufficient to 

eliminate 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 standard 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 22 states have SO2 and NOX

emission reduction responsibilities with respect to the 2006 24-

hour PM2.5 NAAQS. There is 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 
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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.

Thus, 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 of the Transport Rule. For the annual PM2.5

standard, EPA projects that this rule will help assure that all 

areas in the east are brought into attainment. Only one area in 

the East is projected to have a maintenance concern for the 

annual PM2.5 standard in 2014 (Liberty-Clairton).37 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 non-attainment (LibertyClairton) and three areas are projected to have remaining 

 

37 In the Transport Rule proposal, EPA noted that the LibertyClairton 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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maintenance concerns after imposition of the Transport Rule 

(Chicago,38 Detroit, and Lancaster County). 

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 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 

transport-related 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 

 

38 This area is not currently designated as non-attainment 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 non-attainment designation of Chicago-GaryLake County, IL-IN.
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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-downwindstate linkages and using the cost- and air quality-based multifactor approach to quantify significant contribution to 

nonattainment and interference with maintenance (i.e., to 

determine the specific amount of emissions that each upwind 

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 
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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 emissions reductions and large health 

benefits this final rule will 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 
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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 

significant respects. In the NOX SIP 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 
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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, additional emission reductions. 

Therefore, EPA believes that it is appropriate to consider both 
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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 
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the responsibility for achieving or maintaining the NAAQS to the 

upwind state. See 75 FR 45272. 

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.
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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 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 $0/ton, or 

the Base Case level. 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 
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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 

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 the TSD, “Significant 

Contribution and State Emission Budgets” 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 
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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 

contributing states and the downwind receptor state at different 

cost-per-ton levels would have on air quality at downwind 

monitor sites projected to have nonattainment and/or maintenance 

problems.39 While less rigorous than the air quality models used 

 

39 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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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. 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 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.40 

This methodology allows EPA, where appropriate, to define 

multiple cost thresholds that vary for a particular pollutant 

 

40 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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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 has 

been eliminated; each budget also allows for the 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 multifactor analysis EPA uses to determine each 

state’s significant contribution to nonattainment and 

interference with maintenance. State emissions budgets are 
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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 technical support document “Significant Contribution 

and State Emission Budgets”. 

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. 

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

held at $0 per ton (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 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 

that were covered by the Transport Rule as identified in section 
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V.C. For both annual and ozone-season NOX, 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 post-combustion NOX controls in 

covered PM 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 
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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 State in the Transport Rule 

Region at Various Costs Per Ton [(2007$) Per Ton (Thousand 

Tons)]

Base 

Case 

Level $500 $1,000 $2,500 

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 
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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 

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 State in the Transport 

Rule Region 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
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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

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 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 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 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 demand, newlymodeled consent decrees and state rules, and updated NOX rates to 
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reflect 2009 emissions data. All of these factors resulted in 

substantially lower base case TR 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 ozone region and a single threshold of 

$500/ton for annual NOX control in the PM region 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 $0/ton 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 

operations decisions accordingly. For the final rule, EPA 
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included cost thresholds of $500/ton for annual NOX in PM 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. 

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 
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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 

(i.e., $2,800/ton and above), the curve does not include all 

available 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 PM 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. 
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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 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-
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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.

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 2012 to ensure that 

they are achieved as expeditiously as practicable. For SO2 and 

NOX, reductions that come from operating existing controls, 

installing combustion controls, fuel switching, and increased 
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dispatch of lower-emitting generation 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 State in the Transport Rule Region 

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
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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 

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 

cost-effective 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 
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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 for the 

Final Transport Rule Technical Support Document, 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 Technical Support Document 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.”

41 Nitrate replacement occurs when SO2

 

41 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
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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 each nonattainment and 

maintenance receptor to the mix of upwind NOX and SO2 emission 

reductions at each cost threshold. 

As described in section VI.B, 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 areas42). 

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 

 

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

42 Houston and Baton Rouge non-attainment areas
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air quality modeling of this AQAT calibration scenario can be 

found in the Air Quality Modeling Technical Support Document 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 Technical Support 

Document.

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 
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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 

quarterly specific 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 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 
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Page 203 of 1339

estimates from CAMx, finding that the results are unbiased with 

minimal differences. See Significant Contribution and State 

Emission Budgets for the Final Transport Rule Technical Support 

Document 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.43

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 non-attainment and/or maintenance problem in the 2012 base 

 

43 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 multifactor 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 CAMxmodeled concentrations at those receptors under the Transport 

Rule remedy. The paired AQAT-estimated 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 

Technical Support Document.
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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.C) 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 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 
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at the downwind receptors that it significantly affects. If the 

AQAT analysis were to assume emissions reductions in other nonlinked states, the AQAT analysis would then contradict the 1st 

step of our two-step approach to defining significant 

contribution and interference with maintenance. Under EPA’s 

two-step approach, only a state that (1) contributes more than a 

threshold amount to a particular downwind state receptor and (2) 

has emissions 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 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
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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 non-attainment 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 for the Final Transport 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 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 
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indicate diminishing 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

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 non-attainment 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

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 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 
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rule in effect. EPA analysis shows the SO2 emissions 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 Significant Contribution 

and State Emission Budgets for the Final Transport 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 (step 3). 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 
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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 covered Transport Rule States. 

Section VI.C summarizes the estimated air quality impacts in 

2014 of these emission levels at downwind monitor sites, 

including estimates of their nonattainment and maintenance 

status (See “Significant Contribution and State Emissions 

Budgets for the Final Transport 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 
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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 emissions reductions at different levels; whether, 

considering upwind emissions reductions and assumed local (instate) 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 consistent with the cost per ton of 

technologies already widely deployed (similar to the highlycost-effective criteria used in both the NOX SIP Call and CAIR); 

and what cost increase is required to achieve additional 

meaningful air quality improvement.
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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 Clean Air Act. 

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 threshold up to a $2,500 cost threshold would 
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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 

monitors, 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, 
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others suggested EPA continue to exclude non-EGU sources in this 

rulemaking.

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 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 
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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 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 thresholds increase 

above $500/ton. The ozone-season NOX reductions available in the 

Transport Rule region 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 

ozone-season NOX. $500/ton is a reasonable threshold 
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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 

$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 
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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 with the cost thresholds 

identified for SO2 were the appropriate cost thresholds for 

eliminating significant contribution. 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 
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to stem 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, 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 
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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 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
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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),44 and it also is 

projected to resolve the nonattainment and maintenance problems 

with the 24-hour PM2.5 standard 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.

 

44 AQAT results indicated that one receptor in the LibertyClairton 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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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,45 Detroit, and 

Lancaster).46 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 costeffectiveness 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 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 

 

45 This area is not currently designated as non-attainment 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 non-attainment designation of Chicago-GaryLake County, IL-IN.

46 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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this analysis is situated in the “knee-in-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 non-attainment 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, 

Liberty-Clairton is still projected 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 Chicago47

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 

 

47 This area is not currently designated as non-attainment 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 non-attainment designation of Chicago-GaryLake County, IL-IN.
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nonattainment of the 24-hour PM2.5 standard in the LibertyClairton area or the residual maintenance concerns with that 

standard in 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 in comparison with similar 

regulations.
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 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 

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, 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 

Liberty-Clairton area is significantly affected by local 
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emissions from a sizable coke production facility and other 

nearby sources, leading to high concentrations of organic 

carbon in this area.48 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 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.

 

48http:// www.epa.gov/pmdesignations/2006standards/final/TSD/

tsd_4.0_4.3_4.3.3_r03_PA_2.pdf
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 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 cost-effective 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 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 in the ozone region, 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 
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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 in the PM region.

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 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 
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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 in the 

Transport Rule ozone region. EPA also identified a cost 

threshold of $500/ton for annual NOX control for all states in 

the Transport Rule PM region. Finally, EPA identified a cost 

threshold of $500/ton of SO2 for all PM states starting in 2012 

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 in the PM region, 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

modeled in that state in those years represents that state’s 
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emissions once significant contribution to nonattainment or 

interference with maintenance downwind for the relevant PM NAAQS

has been eliminated.

Table VI.D-2 Example of Emission Reductions and Budget 

Formation in Michigan 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 $500 252.4 194.5 57.9

NOX $500 60.6 60.2 0.4

2014 SO2 $2,300 265.6 144 121.6

NOX $500 64.3 57.8 6.5

a Note: In this table, emissions are shown for fossil-fuelfired 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 Michigan. Column C 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 set equal to these emission levels. 

The final column illustrates the emission reductions for the 

state in an average year (before accounting for variability) 

when the cost thresholds are applied - this is equal to the 

emission levels identified at the cost threshold subtracted 

from the base case emission levels.
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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 

and interference with maintenance of the PM2.5 NAAQS considered 

in this rulemaking. As these state emission levels reflect the 

removal of significant contribution, they are reasonable levels 

on which to determine state budgets. Consequently, EPA set 

state budget levels equal to the state level emissions that 

remained at the cost threshold. Each state’s budget corresponds 

to its emission levels following the elimination of significant 

contribution 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 

emissions levels leads to the elimination of significant 

contribution and EPA meets the statutory mandate of 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; however, implementation of these ozone-season NOX

budgets reflects the elimination of significant contribution to 

nonattainment and interference with maintenance of the 1997 
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ozone NAAQS only for 15 states, whereas 11 other states’ ozoneseason NOX budgets reflect meaningful progress toward (but not 

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 

emission 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 ozoneseason 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).

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 
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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.

This budget methodology for the final rule uses projected 

state-level emissions in 2012 and 2014 to set emissions budgets 

for those years on relevant pollutants for that state to control 

under the Transport Rule. EPA’s modeling projects that some 
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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 it also lowers 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, EPA is therefore reducing those states’ 2014 annual NOX
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and ozone-season 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

non-Transport 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 a state rule in Georgia that go 

into effect after 2012 but before 2014. These requirements 

involve the installation and operation of specific advanced 

pollution controls. These source-specific 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 
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these state rule requirements). If EPA did not adjust 2014 

budgets to account for 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 
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that allowing for such emissions growth in covered states beyond 

2012 would be inconsistent with the Transport Rule’s 

identification and elimination of significant contribution 

beginning in 2012. Therefore, for any 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 emissions budget to maintain the same level of the 

2012 emissions budget, thereby disallowing such an emissions 

increase that is inconsistent with the 110(a)(2)(D)(i)(I) 

mandate. Tables VI.D-3 and VI.D-4 below list state emissions 

budgets.

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 1 189,335 106,284

 

85,086 

 

77,238 

Maryland 1 30,120 28,203 
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16,633 16,574 

Michigan 1 194,537 143,995

 

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 20,497 11,823

 

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 3,301,008 2,128,264 1,245,869 1,164,910

Group 1 

Total 2,445,313 1,338,640 NA NA

Group 2 

Total 855,695 789,624 NA NA

Note - These state emissions budgets apply to emissions 

from electric generating units greater than 25 MW and 

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 in 

section VI.E
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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 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 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.49 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 and 

interference with maintenance of the NAAQS considered at the 

linked receptors. At the time of this rulemaking, EPA finds 

 

49 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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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 retire 

its units in early 2012. 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 multifactor 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 Emissions Budgets for 

Electric Generating Units Before Accounting for Variability* 

(tons)

2012 2014

Alabama 31,746 31,499 

Arkansas 15,037 15,037 
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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 

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 greater 

than 25 MW and 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 in 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 baseline emissions. The five states are 

Arkansas, Indiana, Louisiana, Maryland, and Mississippi. These 

states are among those found to exceed the 1 percent
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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 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 baseline 

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.

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 baseline 
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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 limits, although 

equal to the state’s 2012 projected baseline 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 
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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

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.” 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 
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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. Group 2 

states have already eliminated their significant contribution at 

the $500/threshold. So to allow Group 1 or Group 2 allowances 

to be used interchangeably for compliance between the two SO2

regions would be to allow the shifting of reductions from areas 

where they are needed to eliminate significant contribution to 

areas where they are not needed to eliminate significant 

contribution. 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 
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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. Ozone season budgets were set equal 

to the state level emissions from fossil-fuel-fired units 

greater than 25 MW observed at this cost threshold. As 

described in section VI.B, all cost thresholds examined 

reflected the final Transport Rule geography and the marginal 

cost were applied accordingly. Therefore, for an ozone-only 

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 ozone season 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
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(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. Notably, many PM states in the Transport Rule 

region will have annual NOX controls that are likely to keep 

operating year round to address PM 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 
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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, unless EPA 

determined that a lesser reduction would fully resolve the 

nonattainment and/or maintenance problem for all the downwind 

monitoring sites to which a particular state might be linked. 

For these Group 2 states EPA is determining that a lesser 

reduction of SO2, based on the amount of SO2 reductions that can 

be reasonably achieved by 2012 is appropriate. This level is 

defined by the reductions observed in the $500/ton cost 

threshold. 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 
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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 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 fully 

eliminate the significant contribution 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 
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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 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. 

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 
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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 lower under the Transport Rule for the annual 
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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. In particular, emission variability is 

built into the design of power systems, which use a wide mix of 

power generation sources with varying use and emissions 

patterns. Electricity is dispatched to meet loads while 

minimizing costs, with less expensive sources, such as coalfired boilers, generally used before more expensive sources, 

such as natural-gas-fired combustion turbines. Since cheaper 

sources may have very different emission rates –- often, as in 

the case of coal units compared to natural gas units, much 

higher emission rates -- variations in the level of loads can 

have a significant impact on the level of emissions. 

Loads on a power system vary over every time interval, 

changing not only in the short term and seasonally, but also 

annually. Load patterns and levels are determined by a number 

of factors, including economic activity and weather, which vary 

over time. In particular, weather obviously varies not just 
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from season to season but also from year to year, and even small 

changes in annual weather patterns can affect how the power 

system operates 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 how long a heat wave lasts. Similarly, a relatively cold 

winter that drives up winter load may also change what 

generation sources are used. 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. 

In the final Transport Rule, like the proposed rule, EPA 

explicitly takes account of power sector emission variability. 

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 based on projections of state 

emissions in an average year before the elimination of 

prohibited emissions, and state budgets 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 
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variability in loads and power system operations -- state-level 

emissions are likely to vary even after all significant 

contribution to nonattainment and interference with maintenance 

that EPA identified in this final rule are eliminated. EPA 

believes that, because baseline emissions are variable 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). For this reason, 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. 

As discussed in detail in section VII, the limited 

interstate 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. EPA 

believes that the remedy uses variability limits in a way that 

both provides the flexibility of limited interstate trading for 
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dealing with real-world variability in the operation of the 

power system and for reducing costs of compliance with emission 

reduction requirements, as well as providing assurance for 

downwind states that significant contribution to nonattainment 

and interference with maintenance by upwind states will be 

eliminated. 

Moreover, EPA believes that the variability limits are used 

in a way that also does not allow an overall increase in 

emissions. 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 emission rates for all units are held constant) and 

to quantify the magnitude of this variability. 
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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 one-year variability limits calculated using 

a modified approach from the one described in the proposal. EPA 

is not including the proposal’s three-year variability limits in 

the final Transport Rule. EPA received comments that the threeyear variability limits increased program costs and diminished 

compliance flexibility without delivering any additional air 

quality benefits. EGU owners and operators expressed concern 

that three-year variability limits would be impracticable to 

implement and that the one-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 threeyear variability limits would be unnecessary, would be difficult 

to anticipate, and would not have a measurable impact on air 
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quality 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-toyear 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 

three-year variability limit directly from the one-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 one-year limit (see section 2 of 

the “Power Sector Variability” 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. 
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Since the three-year variability limit was based on average 

year-to-year variability over a longer time horizon, EPA notes 

that a random ordering of those years could yield two aboveaverage years in a row. If, by chance, a third above-average 

year were to follow, the state could face violation of the 

three-year limit, even if over a time period longer than three 

years, that state would never have exceeded the statisticallyequivalent one-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 one-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 oneand three-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 three-year limit from the 

one-year variability and section 3 of the “Power Sector 

Variability for the Final Transport Rule” TSD, which describes 

the results of a numerical simulation showing that the one- and 

three-year limits result in similar numbers of exceedances. 
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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 (see section 4 

of the “Power Sector Variability for the Final Transport Rule” 

TSD for more details). This analysis suggests that the air 

quality impacts are small when all upwind states linked to a 

particular receptor monitor increase their SO2 emissions to any 

of the variability levels (5, 10, 15, or 20 percent). 

Furthermore, because the state budgets are based directly 

on IPM modeling of electric generation when cost-effective 

emissions have been removed, 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 one-year variability 

limits without the three-year limits than with the three-year 

limits. See the “Power Sector Variability” 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 statelevel heat input over a 7-year time period (2002 through 2008),
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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 two-tailed 95th percent confidence level is 

the equivalent of the 97.5 percent upper (single-tailed) 

confidence level. Data from 2009 were not included because of 

unusually adverse economic conditions in that year (not 

representative of long-run average year-to-year variability) 

that would potentially skew the variability outcomes for all 

states. This approach yielded an average year-to-year heat 

input variability for each state. EPA multiplied the percentage 

heat input variability value in each state by the emission 

budget to determine the emission variability.

From the state-by-state emission variability values, EPA 

identified a single variability level (percentage) based on the 

historic variability of covered states in the four trading 

programs that would provide adequate flexibility in almost all 

cases. As in the proposal, EPA made the decision to adopt a 

single, uniform percentage level, to the extent possible, 

applicable to all states in favor of simplicity and 

straightforward implementation. Most states’ historic 

variability in year-to-year emissions of the covered pollutants 

(holding emission rates constant) were within 10 percent of 

their average annual emissions. Therefore, for those states and 
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those pollutants, EPA set a variability limit of 10 percent of 

the state budget.

Where EPA’s analysis found states that experienced historic 

variability of a covered pollutant’s emissions greater than 10 

percent of its average annual emissions, EPA rounded those 

budgets’ variability limit percentages up to the next fivepercent increment (e.g., 15 percent, 20 percent) that 

successfully accommodated the historically observed variability. 

In other words, based on their historic variability, states are 

clustered into the following groups for each covered pollutant: 

(1) those with up to 10 percent variability who receive a 10 

percent variability limit; (2) those with historic variability 

exceeding 10 percent but less than 15 percent who receive a 15 

percent variability limit; and (3) those with historic 

variability exceeding 15 percent who receive a 20 percent 

variability limit. For example, for ozone-season NOX emissions, 

EPA determined Louisiana’s historic variability to be over 18 

percent and is thus setting its variability limit at 20 percent 

of its state budget for ozone-season NOX. In this way, each 

state has adequate operational flexibility and total emissions 

are only as high as historical data supports.

This approach is a modification of the proposal, which also 

identified a single variability limit for all states and all 

pollutants (10 percent) but took a slightly different and more 
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complex approach to accommodating states whose historic 

variability exceeded 10 percent. For each pollutant, the 

proposal calculated an absolute tonnage of historic variability 

for the state with the largest exceedance of 10 percent and then 

offered all states the greater of 10 percent or that tonnage 

amount [75 FR 45293]. EPA received comments that the tonnage 

limits were unreasonably large for some states with small 

budgets. In some cases under the proposal’s approach, states 

taking the tonnage amount would have received a variability 

limit of more than 50 percent of their annual budget. As a 

result, these comments led EPA to consider alternative ways to 

accommodate historic variability while avoiding the incidental 

surplus to some states observed above; EPA thus developed this 

final approach as a direct and logical outgrowth that addresses 

the commenters’ objections.

The variability limit approach EPA is finalizing is a 

variation of the proposed approach that results in no material 

change for the majority of states for each pollutant. This is 

the case because most states will have a variability limit equal 

to 10 percent of their budget using either this final approach 

or the proposed approach, so the result is identical. There is 

only one state for SO2 and one state for annual NOX in the final 

rule whose historic variability exceeds 10 percent; there is no 

appreciable difference in the variability limits established for 
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these two states under either approach. The finalized approach’s 

main purpose is to address the phenomenon noted above from the 

proposal’s approach that would otherwise yield surplus ozoneseason NOX variability in a subset of ozone states whose historic 

variability exceeds 10 percent. The final rule’s methodology 

described above yields variability limits that better represent 

these states’ historic variability than the tonnage limitation 

that would emerge from application of the proposal’s 

methodology. The final rule’s approach remains entirely 

consistent with EPA’s objective of allowing EGUs the operational 

flexibility they need while maintaining average annual emission 

reductions required in each state under the rule. 

In both the proposal and this final rule, EPA has avoided 

calculating unique, custom percentages for each state in order 

to simplify the approach, to group states with similar needs, 

and to acknowledge that, by definition, in some years states 

will be above the historical average. EPA believes that 

switching from a single maximum tonnage to a more tailored 

percentage for only those states with relatively high historical 

heat input variability is a reasonable, measured improvement 

that achieves the same objectives, while simplifying the 

variability limits methodology and aligning the limits more 

closely with the amount of flexibility needed by each state. 
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EPA received a number of comments that variability limits 

were too stringent and should be increased to better account for 

actual emission variability or variability in extreme situations 

and to minimize program costs. However, EPA is not increasing 

the broadly applied 10 percent variability limit for the final 

rule because, based on historical data, the Agency believes 

states will have sufficient flexibility and room to operate 

within the final variability limits while achieving elimination 

of significant contribution to nonattainment and interference 

with maintenance in each state. 

F. Variability Limits and State Emission Budgets: State 

Assurance Levels

As explained above, EPA determined variability limits for 

each state and applied the variability limits on a state-bystate 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.
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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 21,603 21,326 237,636 234,584

Georgia 158,527 95,231 15,853 9,523 174,380 104,754

Illinois 234,889 124,123 23,489 12,412 258,378 136,535

Indiana 285,424 161,111 28,542 16,111 313,966 177,222

Iowa 107,085 75,184 10,709 7,518 117,794 82,702

Kansas 41,528 41,528 4,153 4,153 45,681 45,681

Kentucky 189,335 106,284 18,934 10,628 208,269 116,912

Maryland 30,120 28,203 3,012 2,820 33,132 31,023

Michigan 194,537 143,995 19,454 14,400 213,991 158,395

Minnesota 41,981 41,981 4,198 4,198 46,179 46,179

Missouri 207,466 165,941 20,747 16,594 228,213 182,535

Nebraska 65,052 65,052 6,505 6,505 71,557 71,557

New Jersey 5,574 5,574 1,115 1,115 6,689 6,689

New York 20,497 11,823 2,050 1,182 22,547 13,005

North 

Carolina 136,881 57,620 13,688 5,762 150,569 63,382

Ohio 310,230 137,077 31,023 13,708 341,253 150,785

Pennsylvania 278,651 112,021 27,865 11,202 306,516 123,223

South 

Carolina 88,620 88,620 8,862 8,862 97,482 97,482

Tennessee 148,150 58,833 14,815 5,883 162,965 64,716

Texas 243,954 243,954 24,395 24,395 268,349 268,349

Virginia 70,820 35,057 7,082 3,506 77,902 38,563

West Virginia 146,174 75,668 14,617 7,567 160,791 83,235

Wisconsin 79,480 40,126 7,948 4,013 87,428 44,139

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 7,269 7,196 79,960 79,158

Georgia 62,010 40,540 6,201 4,054 68,211 44,594

Illinois 47,872 47,872 4,787 4,787 52,659 52,659
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Indiana 109,726 108,424 10,973 10,842 120,699 119,266

Iowa 38,335 37,498 3,834 3,750 42,169 41,248

Kansas 30,714 25,560 3,071 2,556 33,785 28,116

Kentucky 85,086 77,238 8,509 7,724 93,595 84,962

Maryland 16,633 16,574 1,663 1,657 18,296 18,231

Michigan 60,193 57,812 6,019 5,781 66,212 63,593

Minnesota 29,572 29,572 2,957 2,957 32,529 32,529

Missouri 52,374 48,717 5,237 4,872 57,611 53,589

Nebraska 26,440 26,440 2,644 2,644 29,084 29,084

New Jersey 7,266 7,266 727 727 7,993 7,993

New York 17,543 17,543 2,631 2,631 20,174 20,174

North 

Carolina 50,587 41,553 5,059 4,155 55,646 45,708

Ohio 92,703 87,493 9,270 8,749 101,973 96,242

Pennsylvania 119,986 119,194 11,999 11,919 131,985 131,113

South 

Carolina 32,498 32,498 3,250 3,250 35,748 35,748

Tennessee 35,703 19,337 3,570 1,934 39,273 21,271

Texas 133,595 133,595 13,360 13,360 146,955 146,955

Virginia 33,242 33,242 3,324 3,324 36,566 36,566

West Virginia 59,472 54,582 5,947 5,458 65,419 60,040

Wisconsin 31,628 30,398 3,163 3,040 34,791 33,438

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 3,175 3,150 34,921 34,649

Arkansas 15,037 15,037 3,007 3,007 18,044 18,044

Florida 27,825 27,825 2,783 2,783 30,608 30,608

Georgia 27,944 18,279 4,192 2,742 32,136 21,021

Illinois 21,208 21,208 2,121 2,121 23,329 23,329

Indiana 46,876 46,175 4,688 4,618 51,564 50,793

Kentucky 36,167 32,674 3,617 3,267 39,784 35,941

Louisiana 13,432 13,432 2,686 2,686 16,118 16,118

Maryland 7,179 7,179 718 718 7,897 7,897

Mississippi 10,160 10,160 1,016 1,016 11,176 11,176

New Jersey 3,382 3,382 507 507 3,889 3,889

New York 8,331 8,331 1,250 1,250 9,581 9,581

North 

Carolina 22,168 18,455 2,217 1,846 24,385 20,301
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Ohio 40,063 37,792 4,006 3,779 44,069 41,571

Pennsylvania 52,201 51,912 5,220 5,191 57,421 57,103

South 

Carolina 13,909 13,909 1,391 1,391 15,300 15,300

Tennessee 14,908 8,016 2,236 1,202 17,144 9,218

Texas 63,043 63,043 6,304 6,304 69,347 69,347

Virginia 14,452 14,452 2,168 2,168 16,620 16,620

West Virginia 25,283 23,291 2,528 2,329 27,811 25,620

Note: Budgets, limits, and assurance levels apply to each state’s emissions 

from covered sources, as defined by this final rule, only.

See Section VII.E for the discussion of how variability 

limits and state assurance levels are used in the implementation 

of assurance provisions to limit interstate trading.

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 
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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 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 airquality-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 
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contributions. However, in contrast to CAIR, it then uses a 

state-specific analysis. Instead of identifying a single 

emissions level that could be achieved by the application of 

highly cost effective controls in the region, EPA determines, on 

a state-by-state basis, what reductions could effectively be 

achieved by sources in 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 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 
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it was acceptable for EPA to apply a uniform cost-criterion 

across states. See Michigan, 213 F.3d at 679. In the CAIR 

case, the Court rejected EPA’s analysis, not because it relied 

on cost considerations to identify significant contribution, but 

because it found that EPA had failed to draw the significant 

contribution line at all. See North Carolina, 531 F.3d at 918 

(“. . . here EPA did not draw the [significant contribution] 

line at all. It simply verified sources could meet the SO2 caps 

with controls EPA dubbed ‘highly cost-effective.’”). The 

holdings in Michigan regarding the use of cost and a uniform 

cost-criterion across states were left undisturbed. See, e.g.,

North Carolina, 531 F.3d at 917 (explaining that in Michigan the 

Court held that “EPA may ‘after [a state’s] reduction of all 

[it] could . . . cost-effectively eliminate[],’ consider ‘any 

remaining contribution insignificant”). In fact, the Court 

acknowledged that, based on the Michigan holdings, the 

measurement of a state’s significant contribution need not 

“directly correlate with each state’s individualized air quality 

impact on downwind nonattainment relative to other upwind 

states.” North Carolina, 531 F.3d at 908. 

For these reasons, EPA determined that it was appropriate 

in this rulemaking to consider the cost of controls to determine 

what portion of a state’s contribution is its “significant 

contribution.” However, EPA also heeded the North Carolina
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Court’s warning that “EPA can’t just pick a cost for a region, 

and deem ‘significant’ any emissions that sources can eliminate 

more cheaply.” North Carolina, 531 F.3d at 918. Thus, in this 

rulemaking, EPA departs from the practice used in the NOX SIP 

Call and in CAIR of evaluating, based solely on the cost of 

control required in other regulatory environments, what controls 

would be considered “highly-cost-effective.” Instead, as part 

of its determination of a reasonable cost per ton for upwind 

state control, EPA evaluates the air quality impact of 

reductions at various cost levels and considers the 

reasonableness of possible cost thresholds as part of a multifactor analysis.

In addition, the methodology used in this rulemaking gives 

independent meaning to the interfere with maintenance prong of 

section 110(a)(2)(D)(i)(I). In North Carolina, the Court 

concluded that CAIR improperly “gave no independent significance 

to the ‘interfere with maintenance’ prong of section 

110(a)(2)(D)(i)(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 
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historic variability of their emissions, EPA determined may have 

difficulty maintaining the relevant standards. The specific 

mechanism EPA used to implement this approach is described in 

detail in section IV.C. previously. For annual PM2.5, this 

approach identified 16 maintenance sites in addition to the 32 

nonattainment sites identified in the analysis of nonattainment 

receptors. For 24-hour PM2.5 this approach identified 38 

maintenance sites in addition to the 92 nonattainment sites 

identified in the analysis of nonattainment receptors. For 

ozone it identified 16 maintenance sites in addition to the 11 

ozone nonattainment sites identified.

EPA applied this methodology using available information 

and data to measure the emissions from states in the eastern 

United States that significantly contribute to nonattainment or 

interfere with maintenance in downwind areas with regard to the 

1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. Although EPA 

has not completely quantified the total significant contribution 

of these states with regard to all existing standards, EPA has 

determined, on a state-specific basis, that the emissions 

prohibited in the FIPs are either 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 
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significant contribution to nonattainment and interference with 

maintenance.

VII. FIP Program Structure to Achieve Reductions

A. Overview of Limited Interstate Trading Programs

EPA is finalizing a limited interstate trading remedy that 

is substantially similar to the preferred limited interstate 

trading remedy presented in the proposal. Key differences from 

the preferred limited interstate 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 one-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 
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plants in jurisdictions50 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 remedy in the final rule allows unlimited intrastate 

trading and limited interstate trading to account for 

variability in the electricity sector, but also includes 

assurance provisions to ensure that the necessary emission 

reductions occur within each covered state. The assurance 

provisions restrict EGU emissions within each state to the 

state’s budget with 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 

 

50 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. Simultaneously with this final 

action, EPA is proposing to include Iowa, Kansas, Michigan, 

Missouri, Oklahoma, and Wisconsin in the ozone-season NOX

requirements [insert SNPR FR cite].
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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.

In the final rule, as in the preferred interstate 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 
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ozone-season trading programs respectively, sources may use 

annual NOX and ozone-season 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 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 limited interstate 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 Limited Interstate Trading: The great majority 

of public comments supported the preferred remedy –- limited 

interstate trading. 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 intrastate and 
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limited 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 limited 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 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 
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that allowing interstate trading would increase flexibility to 

meet reduction goals and minimize increases in power costs. 

EPA is finalizing the limited interstate 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, p. 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 limited interstate trading will 

allow source owners to choose among several compliance options 

to achieve required emission reductions in the most costeffective manner, such as installing controls, changing fuels, 
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reducing utilization, buying allowances, or any combination of 

these actions. Interstate trading with assurance provisions 

will also allow the electricity sector to continue to operate as 

an integrated, interstate system able 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 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. 
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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 limited interstate 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 notice, EPA believes the limited 

interstate 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 
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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,51 many environmental 

justice communities are expected to see large health benefits, 

and none are expected to experience any disbenefits, from 

implementing a limited interstate 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 Clean 

Air Act 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 

requirements in this rule, and compliance with Transport Rule 

 

51 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 no way excuses a source from complying with 

other Clean Air Act 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 company-wide 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 limited interstate 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 
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compliance options because a direct control approach would 

directly regulate individual sources by 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 limited interstate 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 
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received, none offered such a solution. For these reasons, EPA 

is not finalizing this approach.

Some commenters offered additional suggestions, such as: 

unlimited trading; using different authorities in the Clean Air 

Act to address interstate transport such as section 110(k)(5) 

and section 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-byunit short-term and long-term performance standards/emission 

rates but suggested adding an overlaid cap and trade program. 

EPA believes the limited interstate 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 used to limit interstate trading are 

needed, since the state-specific budgets would be based on known 
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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-to-year 

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 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 with 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
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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 fossilfuel-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. 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 whether the units were 

covered by the Transport Rule trading programs.

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 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 
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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 provides a full picture of the nature of the unit and 

its operations over time, such as the types of fuels combusted 
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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. 
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EPA notes that the final Transport Rule allows a state to 

submit a SIP revision (abbreviated or full SIPs) under which the 

state may -- 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 Ozone-Season NOX Trading Program to cover fossilfuel-fired boilers and combustion turbines serving –- at any 

time starting January 1, 2005 or later -- an electrical 

generator with a nameplate capacity as low as 15 MWe and 

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 each year thereafter 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 operate as part of a “cogeneration system,” which 

is defined as an integrated group of equipment at a source 
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(including a boiler, or combustion turbine, and a steam turbine 

generator) designed to produce useful thermal energy for 

industrial, commercial, heating, or cooling purposes and 

electricity through the sequential use of energy. In order to 

qualify as a cogeneration unit, a unit also must meet, on a 12-

month or annual basis, 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 

applicability-related provisions, EPA concludes that it is 

reasonable to use 2005, rather than 1990, in the cogeneration 

unit exemption provisions in the final rule.

In the final rule, 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. This is consistent with the approach 

taken in the Acid Rain Program (40 CFR 72.7(b)(4)), where the 
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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 

system-wide 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 
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a year, the unit would not 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 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 
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later of 1990 or the year when it began producing electricity 

and its average annual fuel consumption of non-fossil 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 applicability-related 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 
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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 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 each year thereafter, 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. 

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 
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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.

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. 

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 added to the reduction 

of 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 
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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 they do 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 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 
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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 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 
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nonattainment and interference with maintenance identified by 

EPA is addressed. If EPA were to allow opt-ins, and if any optin 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 occurred 

“anyway” (i.e., even if the unit did not opt in), and the opt-in 

unit would be allocated allowances for the portion of its 

baseline emissions that would be removed by these “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 significant contribution to nonattainment 
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and interference with maintenance. 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 of special concern since 

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 

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 
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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 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 
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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 
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(i.e., even if the boiler had not opted 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 
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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 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

a. Proposed Rule.

EPA proposed an initial phase of reductions in 2012 

followed by a second phase in 2014. Specifically, EPA proposed 
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that sources comply with annual SO2 and NOX requirements by 

January 1, 2012 and January 1, 2014 for the first and second 

phases, respectively. Similarly, EPA proposed sources comply 

with ozone-season NOX requirements by May 1, 2012, and by May 1, 

2014. EPA chose these dates to coordinate with the NAAQS 

attainment deadlines and to assure that reductions are made as 

expeditiously as practicable. The proposal also discussed how 

the compliance deadlines address the Court’s concern about 

timing. 

Relationship to PM2.5 schedule. For all areas designated as 

nonattainment with respect to the 1997 PM2.5 NAAQS, the SIP 

deadline for attaining that standard must be as expeditious as 

practicable but no later than April 2010, with a possible 

extension to no later than April 2015. Many areas have already 

come into attainment by the April 2010 deadline due in part to 

reductions achieved under CAIR. Because the 2010 deadline will 

have passed before the Transport Rule is finalized, EPA proposed 

to coordinate the deadline for eliminating significant 

contribution under this rule with respect to the 1997 PM2.5 NAAQS 

with the April 2015 deadline that applies to areas that will 

need an extension of the April 2010 deadline. For all areas 

designated as nonattainment with respect to the 2006 24-hour 

PM2.5 NAAQS, the attainment deadline must be as expeditious as 
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practicable but no later than December 2014 with a possible 

extension to as late as December 201952.

Upwind emission reductions achieved by the 2014 emissions 

year will help areas that failed to meet the April 2010 deadline 

to meet the April 2015 deadline for the 1997 PM2.5 NAAQS. These 

reductions will also help areas meet the December 2014 

attainment deadline with respect to the 2006 PM2.5 NAAQS. Any 

areas not meeting that deadline can request an extension of up 

to 5 years, to December 2019.

Further, a deadline of January 1, 2014 also provides 

adequate and reasonable time for sources to plan for compliance 

with the Transport Rule and install any necessary controls. EPA 

believes that this deadline is as expeditious as practicable for 

the installation of the controls needed for compliance (see

further discussion in section V.C.2).

 

52 Section 172(a)(2) of the Clean Air Act provides that “the 

attainment date for an area designated nonattainment with 

respect to a national primary ambient air quality standard shall 

be the date by which attainment can be achieved as expeditiously 

as practicable, but no later than 5 years from the date such 

area was designated nonattainment under section 7407(d) of this 

title, except that the Administrator may extend the attainment 

date to the extent the Administrator determines appropriate, for 

a period no greater than 10 years from the date of designation 

as nonattainment, considering the severity of nonattainment and 

the availability and feasibility of pollution control measures.” 

Designations for the 2006 24-hour PM2.5 NAAQS became effective on 

December 14, 2009.
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Relationship to Attainment Deadlines for Ozone. Ozone 

nonattainment areas must attain permissible levels of ozone “as 

expeditiously as practicable,” but no later than the date 

assigned by EPA in the ozone implementation rule (40 CFR part 

51). The areas designated nonattainment in 2004 with respect to 

the 1997 8-hour ozone NAAQS in the eastern United States were 

assigned maximum attainment dates corresponding to the end of 

the 2006, 2009, and 2012 ozone seasons. Many areas have already 

attained due in part to CAIR, federal mobile source standards, 

and other local, state, and federal measures. Those that have 

not yet attained the standard have maximum attainment dates 

ranging from 2010 (these are the 2009 areas that have been 

granted a 1-year extension due to clean data in 2009) to 2018. 

Areas designated “serious” nonattainment areas have a June 2013 

maximum attainment deadline. The proposed Transport Rule’s 

first phase of reductions in 2012 will help the remaining areas 

with June 2013 maximum attainment deadlines attain the 1997 8-

hour ozone NAAQS by their deadline. The reductions will also 

improve air quality in areas with later deadlines. 

Rationale for Requiring Reductions by 2012. EPA proposed 

to require an initial phase of reductions by 2012. EPA proposed 

that these reductions are necessary to ensure that significant 

contribution to nonattainment and interference with maintenance 

are eliminated as expeditiously as practicable. This will in 
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turn assist downwind states to achieve attainment as 

expeditiously as practicable as required by the CAA. Because 

this final rule would replace CAIR, EPA could not assume that 

after this rule is finalized, EGUs would continue to emit at the 

reduced emissions levels achieved by CAIR. Instead, it is the 

emission reductions requirements in the proposed FIPs that will 

determine the level of EGU emissions in the eastern United 

States. For these reasons, EPA proposed to require an initial 

phase of reductions by 2012 which would 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 described 

previously, EPA established the compliance deadlines in the 

proposed rule based on the respective NAAQS attainment 

requirements and deadlines applicable to the downwind 

nonattainment and maintenance sites.

The 2012 deadline for compliance with the limits on ozoneseason NOX emissions is coordinated with the June 2013 maximum 

attainment deadline for serious ozone nonattainment areas 

(taking into account the need for reductions by 2012 to 

demonstrate attainment by that date). This deadline is also 

consistent with the requirement that states attain the NAAQS as 

expeditiously as practicable. 
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The 2014 deadline for compliance with the limits on annual 

NOX and annual SO2 emissions is coordinated with the April 2015 

maximum attainment deadline for areas that received the maximum 

5-year extension of the 5-year attainment deadline for the 1997 

PM2.5 NAAQS (taking into account the need for reductions by 2014 

to demonstrate attainment by April 2015). This 2014 compliance 

deadline is also consistent with December 2014 attainment 

deadline (5 years from designation, in the absence of an 

extension) for areas designated nonattainment for the 2006 PM2.5

NAAQS. Areas unable to meet this 2014 deadline may seek a 

maximum 5-year extension to 2019. 

In addition, the 2012 compliance deadline for the firstphase of annual NOX and annual SO2 emission reductions will 

assure the reductions are achieved as expeditiously as 

practicable. EPA established the interim 2012 compliance 

deadline for annual NOX and annual SO2 reductions because a 

significant number of reductions can be achieved by 2012. 

However, given the time needed to design and construct scrubbers 

at a large number of facilities, EPA believes the 2014 

compliance date is as expeditious as practicable for the full 

quantity of SO2 reductions necessary to fully address the 

significant contribution to nonattainment and interference with 

maintenance. Requiring reductions in transported pollution as 

expeditiously as practicable, as well as within maximum 
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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.

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. 
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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, not 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 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 
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advance of the 2014 attainment date. In light of the 2014 fiveyear 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.

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 
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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 postcombustion 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 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 
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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 Regulatory Impact Analysis (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.

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.
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Table VII.C.2-1 Projected Potential Air Pollution Control (APC) 

Retrofits for Transport Rule53

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 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 in the PM region and ozone-season 

operation of NOX post-combustion controls in the ozone region. 

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. 

 

53 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 PM states, 2) 

operation of scrubbers that are currently scheduled to come 

online by 2012, 3) some sources switching to lower-sulfur coal 

(see Section 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.

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 lowNOX 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 selective 

catalytic reduction (SCR). Assumed improvements and retrofits 

for the January 1, 2012 deadline for NOX therefore only involve 

the much simpler LNB/OFA control modifications or installations. 
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Alternatively, some plant owners might choose to achieve NOX

reductions in a similar time period through an even simpler 

retrofit - selective non-catalytic reduction (SNCR).54

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 region-wide reductions of approximately 28,000 tons of 

annual NOX and 14,000 tons of ozone-season NOX. EPA assumes 

these controls are cost effective at $500/ton and that they 

 

54 David L. Wojichowski, SNCR System – Design, Installation, and 

Operating Experiencehttp://www.netl.doe.gov/publications/

proceedings/02/scr-sncr/wojichowskisystemsummary.pdf
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should be incentivized through budgets given the 2013 attainment 

deadline for ozone areas classified as “serious.” Once 

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 document55, 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.56 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.57 Although such 6-month schedules 

 

55 Technical Support Document (TSD) for the Transport Rule, 

Docket ID No. EPA-HQ-OAR-2009-0491, Installation Timing for Low 

NOX Burners (LNB)

56 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_0

2.pdf

57 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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can be achieved on some units, under favorable circumstances, 

historical projects suggest a more typical schedule would be 12 

to 16 months for the contractor’s portion of the work.58 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.59

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, even if every 

affected unit from the analysis delayed LNB modification or 

installation until the beginning of the 2012 ozone season (10 

months from a June 30, 2011 signature), the emissions 

consequence would be limited to less than 1 percent of most 

 

58 M. O’Donnell, Babcock & Wilcox Company, (personal 

communication with EPA staff, February 22, 2011)

59 N.C Widmer, et al, Coal Power, October 8, 2009, 

http://www.coalpowermag.com/ops_and_maintenance/ZonalCombustion-Tuning-Systems-Improve-Coal-Fired-BoilerPerformance_226.html
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states’ annual NOX budgets, reaching at most 5 percent of only 

one state’s annual NOX budget. In light of this limited 

consequence and the supporting material above, EPA includes LNBdriven NOX reductions in both annual and ozone-season NOX budgets 

for 2012.

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 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.
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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.60

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.61 Note that a dry FGD 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 

 

60 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). 

61 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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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 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 schedule for an entire new coal-fired 

unit, including its APC systems. Springerville Unit 3, for 

example, is a 400 MW coal-fired unit that became operational in 

July 2006, some 33 months after the turnkey engineeringconstruction contractor was given a notice to proceed with 

engineering.62 Springerville was clearly on an accelerated 

 

62 Best Coal-fired Projects, Springerville Unit 3 Expansion 

Project, Power Engineering, November 2006, 

http://www.powergenworldwide.com/index/display/articledisplay/27
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schedule, as its original planned schedule was about 38 months. 

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 

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.

Of the Transport Rule-related FGD retrofits, 0.2 GW is 

projected to use dry FGD, which EPA expects to be simpler and 

quicker installations than those with wet FGD. Half of the 5.9 

 

7709/articles/power-engineering/-/2006/11/best-coal-firedprojects.html
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GW (Muskingum, Rockport) has already been committed under 

consent decrees to add controls or retire;63 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 was ready to 

proceed in 2007, before putting the project on hold.64 The latter 

plant is now facing EPA legal action and the possibility of a 

required expeditious FGD retrofit.65 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 

 

63http://www.epa.gov/compliance/resources/decrees/civil/caa/ameri

canelectricpower-cd.pdf

64http://www.businesswire.com/news/home/20060731005193/en/Contrac

tors-Selected-Install-Emissions-Control-System-Pennsylvania

65http://www.epa.gov/Compliance/resources/complaints/civil/caa/ho

mercity-cp.pdf
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modularization and pre-fabrication of APC components could also 

shorten schedules and reduce job hours. 

EPA believes that the January 1, 2014 compliance starting 

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:

● 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 266, and Asheville Unit 1.

67

● In 2009 the APC supply chain deployed more than six 

times more GW capacity of FGD and SCR controls than the 5.9 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 

 

66 Black & Veatch, 

http://www.bv.com/News_3_Publications/News_Releases/2005/0503.as

px , http://www.bv.com/wcm/press_release/07252007_9767.aspx

67 PowerGenWorldwide, Projects of the Year, January 1, 2007, 

http://www.powergenworldwide.com/index/display/articledisplay/28

2547/articles/power-engineering/volume-111/issue1/features/projects-of-the-year.html
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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 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 
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Page 326 of 1339

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 

sorbent injection (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 capital cost technology that readily can be 

installed in the time frame available for compliance.68,69 

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 

 

68 ICAC letter to Senator Carper, November 3, 2010, 

http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf

69 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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IPM sensitivity analysis to examine a scenario in which FGD 

retrofitting by 2014 is not allowed. Results of EPA’s “no FGD” 

analysis indicate that if the power industry were subjected to 

the requirements of this rule without an FGD retrofit option for 

compliance, 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 TR No FGD in 2014 Scenario Final IPM run.)

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 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 leastcost 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
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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 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 
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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 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 
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from restrictions included in existing coal supply contracts and 

from boiler design constraints that may hinder coal switching 

within a six 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 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 
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to ESP components and flue gas conditioning.70 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 TSD in the docket for this rulemaking.

 

70 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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D. Allocation of Emission Allowances

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 ozoneseason 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 VI.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 committed to be built. The 

remainder of the state budget is allocated to existing units. 

Tables V.D.-3 and V.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 emissions 

allowances for four separate programs: SO2 Group 1 allowances, 

SO2 Group 2 allowances, annual NOX allowances, and ozone-season 

NOX allowances.
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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 later and is usable for compliance only in the 

program for which the allowance was issued. In the annual NOX

program, each annual NOX allowance authorizes the emission of one 

ton of NOX in that vintage year or later 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 later 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 
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This subsection describes the methodology EPA will use in 

the FIPs finalized in this action to allocate to existing 

units.71 The same methodology will be used to allocate 

allowances to existing units for all four trading programs. 

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 would constrain 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 allocations for 2012 will be done 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. 

 

71 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 one full year of quality-assured data on which to base 

a unit’s allocation.
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a. Summary of allocation methodologies and comments

EPA took comment on three distinct allocation 

methodologies. 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. emissions-based allocation methodology 

The emissions-based option presented in the original 

Transport Rule proposal would base allowance allocations to 

existing units on each covered unit’s calculated emissions 

“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 emissions 

allocation methodology. Commenters offered two principle 
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objections. First, they argued EPA should not use unit-level 

model projections to allocate allowances. Second, they argued 

the use of any emissions-based allowance methodology is 

improper. Many of these commenters argued that instead of an 

emissions-based allocation methodology, EPA should use a heatinput-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 emissions budgets, 

they argued that the unit-level model projections were not 

sufficiently accurate to use as a basis for allocating 

allowances. 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 emissions-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 

emissions-based allocation approach.
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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) which 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 emissions 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. 

Many commenters also argued that, even if the emissions 

projections could be adjusted to capture all known and up-todate unit-level operational factors, EPA should not use any 

emissions-based allocation approach. They argued that an 

emissions-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 emissions-based approach. 

Commenters argued that an approach that is not fuel-neutral 
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effectively awards higher-emitting units. Commenters also 

argued that a projected emissions-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 emissions-based 

approach. Under an emissions-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 emissions-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 and allocations 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 emissions-based allocation 

methodology effectively discriminates among covered sources 

based on the type of fuel they combust.

In addition, several commenters argued that the proposal’s 

emissions-based methodology would inappropriately reward the 

highest emitters under the program with more allowances than 

their lower-emitting counterparts would receive. EPA 
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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 emissions-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 specific heat input options and the allocations 

that would result from application of those options to the 

proposed Transport Rule state budgets.
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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 establishes a 5-

year historic heat input baseline for each covered unit and 

allocates 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 emissions-based allocation methodology:

(i) 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 qualityassured data reported by sources from continuous emissions 

monitoring systems, which strengthens its accuracy.

(ii) Historic heat input data are fuel-neutral. 

(iii) Historic heat input data are emissions-controlneutral and thus do not yield reduced allocations for units that 

installed or are projected to install pollution control 

technology. 
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Many commenters also argued that a heat input-based 

allocation methodology should be used because, unlike the 

proposal’s emissions-based 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 upper-bound 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 1.5 lb/mmBtu)). In addition, 

commenters supported the reliance of heat input option 1 on 

continuous emissions monitoring system (CEMS) data that are 

reported to EPA and certified by the source’s designated 
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representative (DR) as accurate and complete. In addition, many 

commenters supported 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 emissions-control neutrality aspects of heat 

input option 1. They noted that this option does not, in 

contrast to the proposal’s emissions-based methodology, penalize 

a source, through a reduced allowance allocation, for having 

chosen a generation technology or emissions control technology 

that was more favorable to public health and the environment. 

EPA agrees with these commenters’ observations. The allocation 

pattern associated with this option does not discriminate 

between 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 to 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 

quality-assured 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 
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individual unit’s share of this historic heat input data is a 

straightforward, clear, and simple calculation to perform, such 

that anyone may easily reproduce EPA’s calculated allowance 

allocations under this approach.

EPA also agrees with commenters that such data has 

previously supported allowance allocation procedures for highly 

successful program implementation of the Acid Rain Program (ARP) 

and the NOX Budget 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 also see a 

heat input-based approach as reasonable.

EPA also agrees with comments observing that allocations 

made under this heat input approach do not discriminate on the 

basis of any unit’s 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 

emissions-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.
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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 combusting natural gas. EPA disagrees 

with the characterization of the excess allowances as “windfall 

profits.” Allocations based on heat-input alone are fuelneutral and control-neutral. The characterization of the heatinput 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 marketbased 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 
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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 outcome as such considerations are not related to 

the statutory mandate of 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.
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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 a 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 costeffective emission reductions and purchasing additional 

allowances through robust markets to cover emissions. 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 uses historic heat input but applies a constraint 

to unit-level allocations under certain circumstances. 

Specifically, under this option unit-level allocations are not 

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 determines whether the 

allocation to a unit under an unconstrained heat-input 
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methodology would exceed that unit’s maximum historic emissions 

of the relevant pollutant since 2003 “in order to reflect unitlevel emissions before and after the promulgation of the CAIR” 

(76 FR 1115). Using this baseline enhances the neutrality of 

the maximum historic emissions data because it captures 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 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 adjusts that maximum 

historic emissions data by applying a “well-controlled rate 

maximum,” designed to place “a reasonably foreseeable maximum 

emissions level 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. 
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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 EPAdetermined “reasonable upper bound capacity factors” and “wellcontrolled 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 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 
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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).72 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 it gives states broad 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 

 

72 CAA section 302(y) defines the term “Federal implementation 

plan” as follows:

Federal implementation plan.—The term “Federal implementation 

plan” means 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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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 emissions-based approach. Most 

commenters favored this historical heat input data basis as the 

most sound and offered technical corrections which EPA has used 

in the final rule. EPA believes it is reasonable to select a 

heat input-based approach for the final Transport Rule as being 

consistent with its program objectives and historically 

established from prior program implementation as a credible, 

workable allocation approach. 
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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 upper-bound 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 allowance allocation under the 

Transport Rule should not discriminate between 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. This approach will avoid 

allocations that effectively penalize units which have 

already invested in cleaner fuels or other pollution 

reduction measures that will continue to deliver 

important emission reductions under this rulemaking. 

The selected approach makes no such discriminations 

and is thus 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 easily 

replicated by any party.

 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. This approach relies on unmodified 

historic data reported directly by the vast majority 
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of covered sources, which 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 Program and the 

Acid Rain Program. Allocation under these programs 

was readily and easily administered and the programs 

achieved or exceeded their environmental goals. This 

approach’s core use of heat input as a basis for 

allocations seeks to build on prior legislative and 

administrative approaches to allowance allocations for 

emission trading programs.

 EPA also finds that this 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 

programs are established to achieve emission 

reductions from covered states. As a group, covered 

sources within each state will make the necessary 

reductions under these programs. In light of the 
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program’s goal to reduce each state’s emissions, it is 

logical that initial allowance allocations to covered 

units should be limited to no more than each unit’s 

maximum historic emissions, as a reasonable starting 

point from which the trading programs would commence 

to assure state-level reductions. Under the trading 

programs, any source may emit any ton for which it 

holds a corresponding allowance, which it may acquire 

either by initial allocation or by subsequent 

purchase. Notwithstanding that compliance flexibility 

of the market-based trading programs under the 

Transport Rule, EPA believes that constraining initial 

heat input-based allowance allocations not to exceed a 

unit’s maximum historic emissions offers a reasonable 

starting point from which the programs can operate. 

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 those prohibited 
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emissions. 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 and 

interference with maintenance.

Consistent with its broad authority in CAA sections 

110(a)(2)(D)(i)(II) and 302(y), EPA believes that data quality, 

fuel-neutrality, control-neutrality, transparency, clarity, and 

successful experience in previous trading programs are 

reasonable factors on which to base the selection of an 

allowance allocation methodology 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 precisely as stated 

in this rulemaking, with clear execution that can be easily 

verified by any citizen with a calculator.
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EPA also believes that the final Transport Rule’s heat 

input-based approach is not inconsistent with the goals of the 

Clean Air Act because it allocates allowances on the basis of a 

neutral factor that does not discriminate by 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 emissions-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 and interference with 

maintenance. The proposal’s emissions-based allocation 

methodology would disadvantage one of two otherwise identical 

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 emissions-based allocation approach, the heat 

input allocation methodology selected by EPA yields a smaller 

proportion of allowances relative to emissions to higheremission-rate units and a higher proportion of allowances 

relative to emissions to lower-emission-rate units. For 
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example, assume that in a state with two units and in a baseline 

year, Unit A combusts 100 MMBtu of heat input and emits 1000 

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 1000-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 to Unit A) 

results in Unit B receiving a larger proportion of its historic 

emissions as an initial allocation share than Unit A receives.

This relative distributional pattern yielded is not 

inconsistent 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 
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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, controlneutral, 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 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 

the best 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 
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because EPA was still in the process of updating its emissions 

inventories and modeling in response to public comments, 

including comments on the Integrated Planning Model. 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 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 five-
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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 five-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 five-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 “three-year average heat input.”

4. The three-year average heat inputs of all covered existing 

units in a state are summed to obtain that state’s total 

“three-year average heat input.”
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5. Each unit’s three-year average heat input is divided by the 

state’s total three-year average heat input to determine 

that unit’s share of the state’s total three-year average 

heat input.

6. Each unit’s share of the state’s total three-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 

allocation. 

7. An eight-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 eight-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 would be identified within the eight-year 

baseline. Similarly, the maximum ozone season NOX emissions 

from the eight-year baseline for each unit would be 

identified. These values are referred to as the “maximum 

historic baseline emissions” for each unit.
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9. If a unit has a 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 would equal the maximum historic baseline 

emission 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” would be reapportioned on the 

same basis as described in steps 1 through 6 to units whose 

historic heat-input-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 number using conventional rounding. The only 

exceptions are for units where the above process results in 

an allocation greater than 0 but less than 1. For these 

units (e.g., a unit with an allowance value of 0.3), their 

allocation is always rounded to 1 allowance.

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
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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

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. Specifically, EPA has 

decided, for each of the four trading programs, to make the 

following units eligible for allocations as new units: any 

covered unit not already receiving an allocation as an existing 

unit (i.e., a covered unit commencing commercial operation on or 

after January 1, 2010); any unit with an existing- or new-unit 

allocation that was not recorded or was deducted because the 

unit was not actually a covered unit but subsequently becomes a 

covered unit; any covered unit with an existing- or new-unit 

allocation that was not recorded or was deducted because the 
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unit relocated out of the state involved and is located in a 

different Transport Rule state; and any covered unit with an 

existing-unit allocation that was not recorded or was deducted 

because the unit stopped operating for three consecutive years 

but resumes commercial operation.73 The final rule, like the 

proposal, adopts procedures for allocating new unit set-aside 

allowances for a given control period based on the units’ 

emissions during the prior control period. 

If, as in the proposal, this were the only process for 

allocating from the new unit set-aside, units would not be 

allocated allowances for their first control period of 

commercial operation, and units that did not commence commercial 

operation around the beginning of a control period would receive 

an allocation based on emissions for less than a full control 

period. Some commenters expressed concern that new units would 

get no allocations for their first year of commercial operation. 

In order to address this concern, EPA is adopting in the final 

rule, provisions expanding the new unit-set-aside allocation 

process to add procedures to allocate to new units for the 

first control period in which the units are in commercial 

 

73

 Existing- or new-unit allocations drawn from the budget of the 

relocated unit’s original state are replaced by new unit setaside 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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operation and increase the allocations, where appropriate, to 

new units for their second control period after commencing 

commercial operation. Specifically, in the final rule, EPA 

revised the new unit set-aside allocation provisions to provide 

a second round of allocations from the new unit set-aside, to 

the extent any allowances remain in the set-aside after 

allocations are made in the first round to units for their 

second or later control period after commencement of commercial 

operation. The first round of new unit set-aside allocations is 

essentially the same as the allocation procedures in the 

proposal and occurs during the control period for which the 

allocations are made. These first round allocations are based 

on unit emissions during the prior control period. The second 

round of allocations occurs after the control period for which 

the allocations are made, but before the allowance transfer 

deadline, and is based on unit emissions during that control 

period. These second round allocations are provided to: new 

units that commenced commercial operation during the control 

period for which the allocations are made and equal the units’ 

emissions during that control period; and new units that 

commenced commercial operation during the prior control period 

and equal the difference (if any) between the allocation that 

the units already received in the first round and their 

emissions during the control period for which the additional 
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allocations are made. However, if insufficient allowances for 

the second round remain in the new unit set-aside, each unit 

will be allocated its proportionate share of the remaining 

allowances. This will be analogous to the process of 

apportioning the new unit set-aside in the first round of 

allocations when there are insufficient allowances in the setaside for the first round. 

In this final rule, EPA is using a slightly different 

methodology for determining the size of the new unit set-aside. 

EPA adjusted the method used in the proposal to account for 

changes in the definitions of “existing unit” and “new unit,” 

and updated modeling. Because EPA is finalizing a different 

allowance allocation approach from the one that was proposed, 

and updating the definition of existing unit as a direct result 

of the allocation approach, it also is updating the new unit 

set-aside calculation to account for more units being classified 

as new, rather than as existing. This is a logical outgrowth of 

the proposal, the NODA on allowance allocations, and updated 

modeling results. 

Similar to the proposed approach, each state’s new unit 

set-aside is initially determined as a fixed percentage of the 

total state budget. However, this modified approach introduces 

a new component that increases the size of the set-aside for 

some states to account for known committed units that would have 
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been considered existing units under the proposal. EPA received 

comments that, under the new definitions, the new unit setaside, as proposed, would be insufficient to meet the needs of 

units already under construction. As a result, EPA analyzed the 

impact of the new allocation approach on new units and made an 

adjustment to address this concern. This is a reasonable 

outgrowth of the definition change and affects where the 

committed units’ allocations originate (i.e., from the state 

set-aside or from the portion of the state budget that is 

allocated to existing units). Further, as discussed below, the 

size of the new unit set-asides is increased to take account of 

committed units so that the share of the state budget available 

for currently uncommitted new units is generally not reduced by 

the eligibility of committed units for new unit set-aside 

allocations. 

For the final rule, EPA adjusted the methodology for 

determining the amounts of allowances in the new unit set-asides 

to reflect the largest new unit set-aside that each state will 

likely need (see “Allowance Allocation to Existing and New Units 

under the Transport Rule Federal Implementation Plans” TSD). 

The final rule creates, for each state, a “base” new unit setaside of 2 percent of the state trading budgets for the SO2 Group 

1, SO2 Group 2, annual NOX, and ozone-season NOX trading 

programs. To this base percentage, a “state-specific” 
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percentage is added to reflect expected emissions from units 

committed to be built in 2010, 2011, or 2012, which are now 

defined as new units, but were defined as existing units under 

the proposed rule. State-specific percentages are well-defined 

because the location of committed units is known. The new unit 

allocation percentages for each state are shown in Table 

VII.D.2-1.

Table VII.D.2-1: Percentage of State Emissions 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%

Illinois 5% 8% 8%

Indiana 3% 3% 3%

Iowa 2% 2% ---

Kansas 2% 2% ---

Kentucky 6% 4% 4%

Louisiana --- --- 3%
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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%

Tennessee 2% 2% 2%

Texas 5% 3% 3%

Virginia 4% 5% 5%

West Virginia 7% 5% 5%

Wisconsin 5% 6% ---
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 Under the final rule, EPA allocates to eligible units 

(except for those in Indian country) allowances from the new 

unit set-aside in the state where the new unit is located for 

the year when the unit first becomes eligible and each year 

thereafter. (As discussed later in this section, a separate 

Indian country new unit set-aside is created for new units in 

Indian country.) 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. These other categories include units that lost their 

existing- or new-unit allocations because the units were not 

actually covered units but where the units subsequently become 

covered units; covered units that lost their existing-unit 

allocations because the units stopped operating for two 

consecutive years but where the units resume commercial 

operation; and covered units that lost their existing- or newunit allocations because the units changed location from one 

state to another. The proposed category of eligible units 

comprising units with a monitor certification deadline after 

January 1, 2012 is removed as unnecessary because the final rule 

uses January 1, 2010 (rather than January 1, 2012, as in the 

proposed rule) as the reference date for determining what units 

receive existing unit allocations.
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Further, the approach in the final rule differs from the 

proposed rule, which would have required that owners and 

operators initially request allowances from the new unit setaside when the unit first became eligible for an allocation. 

EPA 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 such units must make to EPA. EPA concludes that 

requiring owners and operators to submit requests of new unit 

set-aside allocations would impose an unnecessary burden on the 

owners and operators, as well as on EPA, and therefore is 

appropriately removed in the final rule.

The final rule also provides that a unit’s new unit setaside allocation initially equals that unit’s emissions for the 

control period (annual or ozone season) in the preceding year. 

EPA determines whether the total amount of initial allowance 

allocations for all units in a state for a control period 

exceeds the amount in the state’s new unit set-aside for the 

control period. If the amount in the new unit set-aside is 

exceeded, EPA allocates each unit a proportionate share of the 

new unit set-aside based on the unit’s initial allocation 

amount. Any unallocated allowances in the new unit set-aside 
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are allocated to existing units in proportion to their share of 

the current existing-unit allocations. 

The Administrator will issue 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 issued 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 issuance of these 

notices of data availability than the proposed rule. In 

particular, a single set of dates (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 the 

first notice of the second round of allocations, December 15 of 

the year for which the new unit allocations are described in the 

notice and, for the second notice of the second round, February 

15 of the next year) is established for all of the Transport 

Rule trading programs. EPA believes that this 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 issue the notice. Further, the approach of 
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using the same dates 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.

Finally, as discussed elsewhere in this preamble, EPA 

proposed that, if a unit with an existing-unit allocation does 

not operate for three consecutive years, the allowances that 

would otherwise have been allocated to that unit, starting in 

the seventh year after the first year of non-operation, would be 

allocated to the new unit set-aside for the state in which the 

retired unit is located. EPA is retaining this provision but 

changing the time of non-operation to two years and the time of 

allowance allocation to a non-operating unit to four years. 

Starting in the fifth year of non-operation, 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 three 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 

allowances to non-operating units is unnecessary and distorts 

the market. Aside from increasing the size of the new unit setaside in this final rule, described above, EPA is reallocating 
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retired unit allowances to the new unit set-aside after four 

years to make them available for new units in a state. This 

approach allows the new unit set-asides to grow over time.

New Units 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 is a 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 a separate Indian country 

new units 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) under both FIPs and SIPs. 

No tribal new unit set-aside is created for states without 

Indian country. 

Each Indian country new unit set-aside equals a proportion 

of the “base” new unit set-aside included in this final 

Transport Rule (which is calculated as 2 percent of the state 

budget). The “base,” and not total, new unit set-aside is used 

because the other portion of the new unit set-aside (the “statespecific percentage”) specifically accounts for committed units. 

EPA determined the size of the Indian country new unit set-aside 
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(within the state new unit set-aside) by comparing the 

percentage of Indian country to the entire state. This 

percentage (5 percent) represents the maximum percentage of 

Indian country in any state within the Transport Rule region. 

EPA used 5 percent of the state’s new unit set-aside to set the 

Indian country new unit set-aside for all states with Indian 

country. Therefore, the Indian country new unit set-aside is 5 

percent of the 2 percent “base” state new unit set-aside budget, 

or 0.1 percent of the total state budget. 

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. As 

explained above, EPA then took the highest percentage as the 

number to be applied across all states with Indian country to 

determine the Indian country new unit set-aside. 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)
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SO2

2012-

2013

SO2 

2014 

and 

Beyond

Annual

NOX 

2012

Annual

NOX 

2012

OzoneSeason 

NOX 

2012

OzoneSeason 

NOX

2014

Florida --- --- --- --- 28 28

Iowa 107 75 38 37 --- ---

Kansas 42 42 31 26 --- ---

Louisiana --- --- --- --- 13 13

Michigan 195 144 60 58 --- ---

Minnesota 42 42 30 30 --- ---

Mississippi --- --- --- --- 10 10

Nebraska 65 65 26 26 --- ---

New York 20 12 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 79 40 32 30 --- ---

Under the FIPs, EPA manages and distributes allowances from 

Indian country new unit set-asides in largely the same manner as 

for state new unit set-asides. The approach for determining the 

number of allowances allocated to new units is the same for both 

types of new unit set-asides. One difference between the two 

types of new unit set-asides is the handling of unused 

allowances. Unallocated Indian country new unit set-aside 

allowances are transferred back into the state new unit setaside and made available to new units in the rest of the state 

and then to existing units. 
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Under a SIP, EPA retains that portion of the state budget 

equal to the Indian country new unit set-aside. EPA continues 

to manage and distribute the Indian country new unit set-aside 

allowances in essentially the same manner as under the FIPs. 

The state will determine in a SIP how (allocation methodologies) 

and to whom (e.g., existing units, new units, or entities with 

energy efficiency (EE) projects, or whether to auction 

allowances) to allocate allowances from the rest of the state 

budget. Unallocated allowances in the Indian country new unit 

set-aside are returned to the portion of the state budget 

allocated under the SIP allocation provisions. Note that 

allowances are only allocated from the Indian country new unit 

set-aside if and when a covered EGU is constructed in Indian 

country and otherwise are returned to the state budget for 

allocation to existing or new units, or EE projects, as 

applicable. Unallocated allowances are not provided to the 

Tribes.

EPA believes that this approach is reasonable because this 

increases the likelihood of having sufficient allowances to 

allocate to new units in a state, whether or not the new units 

are located in Indian country, and, in the case of a SIP, 

provides the state flexibility in determining allocations once 

allocations have been provided for Indian country new units. As 

with the state new unit set-aside under FIPs, EPA will identify 
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the new units qualifying for the Indian country new unit setaside (under FIPs and SIPs), calculate the allocations, and 

issue notices of data availability using the same schedules as 

notices for the state new unit set-aside.

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 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 
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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 one 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.F 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 in 

section VI.F of this preamble. The basis for the variability 

limits is also described in section VI.F of this preamble. 

Additional details may be found in the Power Sector Variability 

TSD and Power Sector Variability Analyses for the Final 

Transport 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 
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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 

DR’s share of the state assurance level (regardless of whether 

the source had enough allowances to cover its emissions) during 

the control period.74 

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 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 

 

74 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 the allowance transfer deadline for the control period 

involved.
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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 many 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 
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designated representative with owners and operators of other 

units in the 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 requirement. Some commenters stated that 

this is a reasonable approach. 
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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 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 these 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 limit incentives to trade and ensure that state emissions 

will 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 
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variability limit, the greater the risk of being subject to the 

assurance provision penalties. 

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 setaside 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 

available in the state’s new unit set-aside.75 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 emissions number applies 

 

75 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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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 emissions number 

is essentially unchanged from the proposal [75 FR 45313]. For 

more details on capacity factors for new units, see Capacity 

Factors Analysis for New Units 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.G of 

this preamble.

Other features of the limited interstate trading programs 

work in conjunction with the assurance provisions to ensure 

state emissions do not exceed state assurance levels. The 

limited interstate trading programs have: state-specific budgets 

that do not include the variability limits and that are the 

basis for allocating allowances in each state; a requirement 

that owners and operators of each source hold enough of these 

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 
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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 

levels. The accumulated data, history, and experience from cap 

and trade programs underscore that emission reductions 

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.

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. This penalty level is a change 
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from the proposal, in which one allowance was to be surrendered 

for each ton of emissions over the 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 for the Final Transport 

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 66 tons (60 * 110

percent), but actually emitted 75 tons during the control 

period, or 9 more than their share of the state assurance level. 

Since the state, as a whole exceeded the state assurance level 

by 26 tons, DR1’s share of the penalty is 35 percent (9/26) of 

the total penalty, or 17 allowances (35 percent of 50). 
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Figure VII.E-1 Assurance Provision Penalty Examples

Number of 

Allowances 

Allocated

Allocation 

+ % of 

var. limit

Total 

Emitted

Number of 

Allowances

above 

Allocation

# over 

Alloc + 

% of 

var.

limit

Share of 

Exceedance 

(%)

Penalty

(# 

Allowances) 

DR1 60 66 75 15 9 35% 17

DR2 20 22 35 15 13 50% 25

DR3 10 11 15 5 4 15% 8

DR4 10 11 10 - - - 0

TOTAL 100 110 135 35 25 100% 50 

DR1, DR2, DR3, and DR4 are all in the same state.

State budget plus 10% variability limit is 110 tons (100 + 10 = 

110).

State exceeded its assurance level by 25 tons (135 - 110 = 25). 

Penalty is 50 allowances (2 x 25 = 50).

Some numbers may not add up due to rounding

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 
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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 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 offset and the excess emissions penalty are automatic 
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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 (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 
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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 allowanceholding 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 emission 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 violation when a 

unit has excess emissions for the calendar year, the courts have 

addressed this question. In decisions applying the discretionary 
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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 
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Program regulations state that any allowance deduction, excess 

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 
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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

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 

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 
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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 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 
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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.

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
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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. 

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 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 
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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. 

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 oiland 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. 
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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 annual NOX and 

ozone-season 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 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 yearround basis as they have under CAIR. Therefore, units in the 

following states must monitor and report both SO2 and NOX year-
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round under the Transport Rule: Alabama, Georgia, Illinois, 

Indiana, Kentucky, Maryland, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 

Virginia, and West Virginia.

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 trading program was similarly subject to only the ozoneseason 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. 
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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 one 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 monitoring equipment needed is not 

extensive or is largely in place already for the purpose of 
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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 
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final rule, the requirement that a unit hold enough allowances 

to cover its emissions starts on the later of the 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 
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CFR Parts 70 and 71.

76 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 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. 

 

76 Part 70 addresses requirements for state Title V programs, and 

Part 71 governs the federal Title V program.
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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 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 
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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 emissions monitoring system, an excepted monitoring 

system under appendices D and E to Part 75, a low mass emissions 

excepted monitoring methodology under §75.19, or an alternative 

monitoring system under subpart E of Part 75). 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 
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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 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 
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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)).

77 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. 

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 

 

77 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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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 new source 

review (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 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 
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Support document which is available on EPA’s website at: 

http://epa.gov/cair/pdfs/0053-2263.pdf

Because GHG 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 New Source Review 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 

increase by at least 75,00078 tons per year of CO2 equivalent 

(CO2e). 

 

78 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 
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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 greenhouse gas (GHG), and it 

shows that New Source Review (NSR) requirements would 

not significantly impact the construction of controls 

that are installed to comply with the proposed 

Transport Rule. 

(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. 

 

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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EPA received a number of comments on the NSR issue, which 

can be divided into four types of comments: (1) comments 

related to GHGs, (2) comments related to sulfuric acid mist, (3) 

comments related to CO emissions 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 an 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.79 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 

 

79 “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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these commenters noted that reagent injection was necessary to 

avoid triggering NSR for sulfuric acid mist when their SCR was 

installed.

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 (OFA) 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 
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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 recommend that EPA should waive transport 

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 
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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 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.

80

 

80 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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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 percent of on-site generation.81 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 five-year historic 

 

81 Documentation Supplement for EPA Base Case v.4.10_FTransport –

Updates for Final Transport Rule.
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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 emissions increase to less than the 75,000 tons per year 

threshold for triggering NSR.

As discussed in section VII.D, 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.D, 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 
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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 emissions 

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 emissions increases that 

would trigger NSR, including but not limited to alternative SO2

reduction strategies or technologies, efficiency improvements, 

or the ability to adjust net 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.D for more 
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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 this 

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, 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 
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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 ozoneseason NOX budgets. Covered sources have a suite of NOX

pollution control strategies and technologies available to them, 

including coal selection, selective non-catalytic reduction 

(SNCR), gas re-burn, low-NOX burner (LNB) and overfire air (OFA) 
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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
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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 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 best available control technology (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 limited interstate trading program established by this 

rule eliminates all of the emissions that EPA has identified as 

significantly contributing to downwind nonattainment or 

interference with maintenance82 in a manner that is consistent 

 

82 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 
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with section 110(a)(2)(D)(i) of the CAA as interpreted by the 

D.C. Circuit in North Carolina, 531 F.3d 896. The FIPs 

finalized in this action require sources to participate in 

emissions trading programs that allow intrastate trading and 

limited interstate trading, and that also include provisions to 

ensure that no state’s emissions exceed that state’s budget with 

variability limit. These assurance provisions, combined with 

the requirement that all sources hold 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 EPA has 

determined must be prohibited pursuant to section 

110(a)(2)(D)(i)(I). However, for the reasons explained above, 

 

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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the amount of emissions that remain after such emissions are 

eliminated 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 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 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 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 state specific 

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. 
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In addition, the requirement that all sources hold emission 

allowances (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 multiple states, 

factors that affect electricity generation, and thus EGU 

emissions levels, are more likely to vary significantly within 

the region so that resulting emissions changes in different 

parts of the region are more likely to offset each other. For 

example, a broad region can encompass states with differing 

weather patterns, with the result that increased electricity 

demand and emissions due to weather in one state may be offset 

by decreased demand and emissions due to weather in another 

state. By further example, a broad region can encompass states 
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Page 426 of 1339

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 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 or interference with maintenance. 
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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 limited interstate 

trading remedy 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 

limited 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 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 
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Page 428 of 1339

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 

notice, EPA has addressed these concerns by using source 

specific analysis to identify each individual state’s 

significant contribution 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. 

Moreover, as discussed above, variability is inherent to 

the operation of the electric generation system and thus to 
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emissions from this sector. In fact, variability in emissions 

occurs every year in every state and, like variability of yearto-year weather conditions (which is a major cause of emission 

variability), cannot be accurately predicted. See the Power 

Sector Variability 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 

provisions take into account inherent variability over time of 

emissions from this sector while ensuring that the number of 

allowances from other states that can be purchased for use by 

sources in any given state is fixed at a relatively low level. 

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

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 
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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

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

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, 
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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 statelevel 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

Emissions

Reductions 

from 2005

2014 

Transport 

Rule

Emissions

2014

Emissions

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, 
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Page 432 of 1339

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

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
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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

2012 2014 2012 2014

Alabama 34,074 31,365 31,607 29,532
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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 
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Page 435 of 1339

eastern U.S. modeling domain83. Modeling was performed for the 

2014 base case and the 2014 “Limited Interstate 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 

Technical Support Document. 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

84. 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.

 

83 As described in the Air Quality Modeling Technical Support 

Document, 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.

84 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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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

Annual PM2.5

Nonattainment 

Sites85

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

 

85 “Nonattainment” is used to denote sites that are projected to 

have both nonattainment and maintenance problems.
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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 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 

12 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 

maintenance-only sites by 81 percent in 2014 compared to the 

2012 base case. The average reduction in 24-hour PM2.5 across 

the 20 2012 nonattainment sites is 6.8 μg/m3 and the peak 

reduction at an individual nonattainment site is 11.7 μg/m3. 
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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 the 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.

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 
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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 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.

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 
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Page 440 of 1339

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 study86 and the 

other based on the extended Six Cities cohort study87. 

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 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).

88 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 nonfatal 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. 

 

86 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.

87 Laden et al., 2006. ‘‘Reduction in Fine Particulate Air 

Pollution and Mortality.’’ American Journal of Respiratory and 

Critical Care Medicine. 173:667–672.

88 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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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 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 
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Page 442 of 1339

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)

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)
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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)

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 benefits estimates we 
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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 would 

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 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 
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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. 

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 PM2.5 & O3 $0.003 --- $0.003
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visits for asthma ($0.002—

$0.006)

($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

($0.004—

$0.013)

---

$0.01

($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.
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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.

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 
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Transport Rule region 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 cost-effectiveness estimates. 

In estimating the net benefits of regulation, the appropriate 

cost measure is ‘‘social costs.’’ Social costs represent the 

welfare costs of the rule to society. These costs do not 

consider transfer payments (such as taxes) that are simply 

redistributions of wealth. The social costs of this rule 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 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) 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 are 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
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Social costs

3% discount rate $0.81

7% discount rate $0.81

Total monetized benefitsb

3% discount rate

7% discount rate

$120 to $280

$110 to $250

Net benefits (benefits-costs)

3% discount rate

7% discount rate

$120 to $280

$110 to $250

a All estimates are for 2014, and are rounded to two significant 

figures.

bThe 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 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 
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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 to the quantified costs of the program on the power 

sector. However, EPA’s experience and results of independent 

evaluation suggests that costs are likely to be lower by some 

degree (see RIA for details). The annualized cost estimates 

presented are the best and most accurate based upon available 

information. In a separate analysis, EPA estimates the indirect 

costs and impacts of higher electricity prices on the entire 

economy. These impacts are summarized in the RIA for this final

rule.
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Every benefit-cost analysis examining the potential effects 

of a change in environmental protection requirements is limited 

to some extent by data gaps, limitations in model capabilities 

(such as geographic coverage), and uncertainties in the 

underlying scientific and economic studies used to configure the 

benefit and cost models. Gaps in the scientific literature often 

result in the inability to estimate quantitative changes in 

health and environmental effects. Gaps in the economics 

literature often result in the inability to assign economic 

values even to those health and environmental outcomes that can 

be quantified. While uncertainties in the underlying scientific 

and economics literatures (that may result in overestimation or 

underestimation of benefits) are discussed in detail in the 

economic analyses and its supporting documents and references, 

the key uncertainties which have a bearing on the results of the 

benefit-cost analysis of this rule include the following: 

• EPA’s inability to quantify potentially significant benefit 

categories; 

• Uncertainties in population growth and baseline incidence 

rates; 

• Uncertainties in projection of emission inventories and air 

quality into the future; 

• Uncertainty in the estimated relationships of health and 

welfare effects to changes in pollutant concentrations including 
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the shape of the C–R function, the size of the effect estimates, 

and the relative toxicity of the many components of the PM 

mixture; 

• Uncertainties in exposure estimation; and 

• Uncertainties associated with the effect of potential future 

actions to limit emissions. 

Despite these uncertainties, we believe the benefit-cost 

analysis provides a reasonable indication of the expected 

economic benefits of the rulemaking in future years under a set 

of reasonable assumptions. This approach calculates a mean value 

across VSL estimates derived from 26 labor market and contingent 

valuation studies published between 1974 and 1991. The mean VSL 

across these studies is $6.3 million (2000$).89 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: 

 

89 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 
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Page 454 of 1339

upon which the Transport Rule is based were selected from the 

peer-reviewed scientific literature. We used up-to-date 

assessment tools, and we believe the results are highly useful 

in assessing this rule. 

There are a number of health and environmental effects that 

we were unable to quantify or monetize. A complete benefit-cost 

analysis of the Transport Rule requires consideration of all 

benefits and costs expected to result from the rule, not just 

those benefits and costs which could be expressed here in dollar 

terms. A listing of the benefit categories that were not 

quantified or monetized in our estimate are provided in Table 

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
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—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

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 
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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? 

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? 
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Atmospheric deposition of sulfur and nitrogen, often 

referred to as acid rain, occurs when emissions of SO2 and NOX

react in the atmosphere (with water, oxygen, and oxidants) to 

form various acidic compounds. These acidic compounds fall to 

earth in either a wet form (rain, snow, and fog) or a dry form 

(gases and particles). Prevailing winds can transport acidic 

compounds hundreds of miles, across state borders. Together 

these emissions are deposited onto terrestrial and aquatic 

ecosystems across the U.S., contributing to the problems of 

acidification. 

(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 
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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 mid-Appalachian highlands) 

and southeastern streams. 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 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 
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plant to take up water and nutrients, especially calcium.90 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,91 leading 

to increased mortality of canopy trees. 

Both coniferous and deciduous forests throughout the 

eastern U.S. are experiencing gradual losses of base cation 

nutrients from the soil due to accelerated leaching 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 

 

90 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.

91 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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U.S. Acidifying deposition has been implicated as a causal 

factor.92

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. 

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) 

 

92 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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suffered from moderately high or high levels of eutrophication 

due to excessive inputs of both N and phosphorus, and a majority 

of these estuaries are located in the coastal area from North 

Carolina to Massachusetts.93 For estuaries in the Mid-Atlantic 

region, the contribution of atmospheric distribution to total N 

loads is estimated to range between 10 percent and 58 percent.94

Eutrophication in estuaries is associated with a range of 

adverse ecological effects. The conceptual framework developed 

by NOAA emphasizes four main types of eutrophication effects: 

low dissolved oxygen (DO), harmful algal blooms (HABs), loss of 

submerged aquatic vegetation (SAV), and low water clarity. Low 

DO disrupts aquatic habitats, causing stress to fish and 

shellfish, which, in the short-term, can lead to episodic fish 

kills and, in the long-term, can damage overall growth in fish 

and shellfish populations. Low DO also degrades the aesthetic 

qualities of surface water. In addition to often being toxic to 

fish and shellfish, and leading to fish kills and aesthetic 

impairments of estuaries, HABs can, in some instances, also be 

harmful to human health. SAV provides critical habitat for many 

 

93 National Oceanic and Atmospheric Administration (NOAA). 2007. 

Annual Commercial Landing Statistics. August. 

http://www.st.nmfs.noaa.gov/st1/commercial/landings/annual_landi

ngs.html.

94 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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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 region. Thus, 

reductions in the levels of nitrogen deposition will have a 

positive impact upon current eutrophic conditions in estuaries 

and coastal areas in the region. 

c. Mercury Methylation and Deposition 

Mercury is a highly neurotoxic contaminant that enters the 

food web as a methylated compound, methylmercury.95 The 

 

95 U.S. Environmental Protection Agency (U.S. EPA). 2008. 

Integrated Science Assessment for Sulfur Oxides - Health 

Criteria (Final Report). National Center for Environmental 
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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.96,97

The SO2 ISA concluded that evidence is sufficient to infer a 

casual 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.98 In terms of forest productivity and ecosystem 

diversity, ozone may be the pollutant with the greatest 

 

Assessment, Research Triangle Park, NC. September. 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843.

96 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.

97 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.

98 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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potential for regional-scale forest impacts.99 Studies have 

demonstrated repeatedly that ozone concentrations commonly 

observed in polluted areas can have substantial impacts on plant 

function.100,101

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 ozoneexposure/tree-response functions by exposing tree seedlings to 

different ozone levels and measuring reductions in growth as 

‘‘biomass loss.’’ Typically, seedlings are used because they are 

easy to manipulate and measure their growth loss from ozone 

pollution. The mechanisms of susceptibility to ozone within the 

leaves of seedlings and mature trees are identical, and the 

decreases predicted using the seedlings should be related to the 

decrease in overall plant fitness for mature trees, but the 

 

99 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.

100 De Steiguer, J., Pye, J., Love, C. 1990. Air Pollution 

Damage to U.S. Forests. Journal of Forestry, 88(8), 17-22.

101 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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magnitude of the effect may be higher or lower depending on the 

tree species.102 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 longterm ecological harm as the short-term negative effects on 

seedlings compound to affect long-term forest health.103

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.104 In addition, many 

 

102 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.

103 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.

104 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. 
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businesses rely on healthy-looking vegetation for their 

livelihoods (e.g., horticulturalists, landscapers, Christmas 

tree growers, farmers of leafy crops, etc.) and a variety of 

ornamental species have been listed as sensitive to ozone.105

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 

 

http://www.epa.gov/ttn/naaqs/standards/ozone/data/2007_07_ozone_

staff_paper.pdf.

105 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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$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 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, please 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/epaipm/index.html.

EPA also included an analysis of impacts of the final rule 

to industries outside of the electric power sector by using the 

Multi-Market 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 
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economic impacts for the proposed Toxics Rule, 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 [will insert 

final results when available and change associated text if 

necessary]. Documentation for the Multi-Market Model can be 

found in the RIA for this final rule.

Also note that as explained in section V.B (Baseline for 

Pollution Transport Analysis), the baseline used in this 

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

assume that reductions from CAIR would continue indefinitely, 

areas that are in attainment solely due to controls required by 

CAIR would again face nonattainment problems because the 

existing protection from upwind pollution would not be replaced. 

As explained in that section, EPA believes that this is the most 

appropriate baseline to use for purposes of determining whether 

an upwind state has an impact on a downwind monitoring site in 

violation of section 110(a)(2)(D).

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 
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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 of roughly 2,250 

job-years in direct employment impacts in 2014. 

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 Toxics Rule. For more information, 
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please refer to the TSD for this analysis, “Employment Estimates 

of Direct Labor in Response to the Final Transport Rule in 

2014.”

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 Toxics Rule. 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 additional $1 million spending on 

pollution abatement results in an small net increase of 1.6 

jobs; the estimated effect is not statistically significant 

different from zero. As a result, the authors conclude that 
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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 inflation adjustment factor used in the analysis.

b According to the 2007 Economic Census, the electric power 

generation, transmission and distribution sector (NAICS 2211) 

had approximately 510,000 paid employees.
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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 

improvements in homes, buildings, and industry (EE) 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 emissions 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 federal programs authorized under 
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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 Mid-Atlantic 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 emissions 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 guidance106 concerning the recognition, in SIPs, of 

emission reduction benefits of energy efficiency and has 

approved the inclusion of EE measures in individual SIPs.107

 

106 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

107 Metropolitan Washington Council of Governments developed a 

regional air quality plan for the eight-hour ozone standard for 

the DC Region non-attainment area that included an EE measure. 

The plan was adopted by Virginia, Maryland, and the District of 
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While all remedy options considered in the proposed rule 

would have lead to an increase in the relative costeffectiveness of EE 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 more 

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 

 

Columbia and the respective ozone SIPs were approved by the EPA 

regions in 2007.
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infrastructure that many states already possess. Instead of 

establishing EPA-administered 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 circumstances if they choose. EPA 

anticipates providing additional information in the future for 

states on EE set-asides, as needed.108

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 setasides) 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 stateimplemented EE set-asides. 

IX. Related Programs and the Transport Rule

 

108 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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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. 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
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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

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
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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 the next section and State Implementation Plans (SIPs) are 

discussed in section X of this preamble.

Compliance deadlines. The first phase of Transport Rule 

reductions commences January 1, 2012 for annual NOX and SO2

requirements and May 1, 2012 for ozone-season NOX requirements. 

The second phase commences January 1, 2014 for annual NOX and SO2

requirements and May 1, 2014 for ozone-season NOX requirements.

In contrast, the first phase of CAIR NOX reductions 

commenced January 1, 2009 for annual NOX requirements and May 1, 

2009 for ozone-season 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 
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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 noncovered 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.

Second, the Transport Rule FIPs’ ozone-season NOX trading 

program applicability provisions do not cover NOX SIP Call small 

EGUs and non-EGUs 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.
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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 the following section 

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 emissions 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 not impose limitations on 

interstate allowance trading or 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 
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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 and 

thereafter 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 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 
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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 modify certain 

elements of a Transport Rule FIP trading program in order to 
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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, if some other methodology is used, 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 
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to the NOX SIP Call. However, for the reasons discussed 

elsewhere in this preamble, this 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.

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 period 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
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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 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 
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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 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. 
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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 an 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 period 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, 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, 
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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 

but continue to participate 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 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
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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 ozoneseason 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. 

The final rule provides states an option to expand the 

general applicability provisions of the Transport Rule ozoneseason 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 
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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 Trading Program), the final Transport Rule, like the 

proposed rule, does not allow expansion of the general 
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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.109 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 for nonEGUs 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 jeopardize 

the state’s ability to show that significant contribution to 

 

109 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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nonattainment or interference with maintenance has been 

eliminated. (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 the CAIR programs. 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. 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 emissions. 
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This approach 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 allowanceholding requirements, in part, because EPA was concerned that 

those approaches would be perceived as inconsistent with the 

requirements of 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. 
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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 continue, of course, to be usable for 

compliance in the Acid Rain Program.110

(2) NOX Allowance Banks

In the proposed rule, EPA estimated that the CAIR ozoneseason NOX bank would contain over 600,000 allowances and the 

CAIR annual NOX bank would contain about 720,000 allowances after 

completion of true-up 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 

 

110 The Title IV allowance bank is expected to be about 14 million 

tons at the beginning of 2012.
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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;

 Factor the bank into the calculation of state NOX budgets by

reducing the state NOX budgets to take account of the banked 

pre-2012 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.
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 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, and the CAIR ozoneseason 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 ozoneseason 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 Trading 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 ozoneseason 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
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allowances expected to remain unused represent nearly threequarters of aggregate state ozone season NOX budgets111 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. 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 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 

 

111 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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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 results 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 which 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 
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the 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, stateby-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-byunit 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-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 acknowledges that, as a general principle, it is 
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desirable to provide continuity between sequential regulatory 

programs involving emissions trading and thereby to ensure that 

allowances in the past program continue to have some value in 

the new program. However, 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 on April 14, 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 continue to have 

value in the future.”112 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 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 

 

112http://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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treatment, in any future trading programs, of any past trading 

program’s banked allowances.

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 ozone-season NOX trading program would achieve 

the emission reductions required by the NOX SIP Call from EGUs 

serving generators with a nameplate 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 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 
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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 non-EGUs) 

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 obligations to meet those requirements 
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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
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The final rule does not affect any Acid Rain Program 

requirements. Acid Rain requirements are established 

independently in Title IV of the CAA and are not replaced by the 

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. 
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There is a discussion of possible emissions increases in noncovered 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, nor Regional Haze BART-related requirements. For that 

reason, we are 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 explained in proposal (75 FR 45342) that for each 

upwind state covered by the proposed Transport Rule, EPA 
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proposed state-specific emission reductions requirements with 

respect to one or more of three air quality standards –- the 

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

1997 ozone NAAQS. In CAIR, EPA allowed the states to replace 

the CAIR FIP with SIPs and provided substantial flexibility and 

proposed to allow similar flexibility to states for addressing 

the 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 determined 

based on the state emission budgets provided in the final 

Transport Rule.

EPA received comments suggesting that if the proposal’s

remedy is 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 
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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 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 gave the specific provisions in the FIP 

that 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 
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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 each year could not exceed the applicable 

budget, 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, and that no 

other provisions of the FIP are 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) that adopted trading program regulations meeting 

certain requirements for control period 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 opt-in units) or other entities (such as 

renewable energy facilities) or could auction allowances. Upon 
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EPA approval of a state’s full SIP, the state’s SIP-based 

trading program would be integrated with the comparable FIPbased 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 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.

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 which EPA 

would review on a case-by-case basis (76 FR 1120).
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Suggested deadlines for abbreviated and full SIPs were 

given in tables in the NODA (76 FR 1120) and generally required 

states to submit SIPs about 2 years ahead of a particular 

control period for which state allocations would apply to give 

EPA time to review and approve the SIP and record allowances.

There were also comments that supported EPA’s proposed 

approach. Most commenters advocated for state allocation 

options within the preferred FIP remedy. NODA comments largely 

supported state allocation options which 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) and 97.412(a) (for the annual 

NOX trading program), §§97.511(a) and (b) and 97.512(a) (for the 

ozone-season NOX trading program), §§97.511(a) and (b) and 

97.612(a) (for the SO2 Group 1 trading program), and §§97.511(a) 

and (b) and 97.612(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 new 
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units)113 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 all FIPs that apply or some 

subset of the FIPs that apply to a particular state leaving in 

place the FIPs for the requirements not addressed by a SIP.

Further, only if the state replacement for the Transport 

Rule FIP allocation provisions meet certain requirements and the 

abbreviated SIP does not change any other provisions in the 

Transport Rule FIP trading program, EPA will approve the 

abbreviated SIP. For EPA approval, the state allocation 

provisions must meet the following requirements. First, the 

provisions must provide that, for each year for which the state 

allocation 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, which will continue to be 

 

113 EPA is not finalizing opt-in provisions, so the reference to 

federal-only allocations given in the NODA has been removed.
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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 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 
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discussed in detail in section XI of this preamble, provide that 

the Administrator must record existing-unit allowance 

allocations and auction results by: July 1, 2013 for 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 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. 

Third, to the extent the state provisions establish an 

allowance auction, the provisions must require the following 

treatment of each allowance purchased by a covered unit in the 
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state in such an auction. Solely for purposes of defining and 

determining “common designated representative’s share” for 

implementation of the assurance provisions, each such allowance 

must be treated as an allowance allocated to that unit.

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 in only a limited 

way: i.e., by including 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. (The state’s full SIP trading program must 

include provisions that are the same as those in the Transport 

Rule FIP trading program for the Indian country new unit setaside.) In the state allocation or auction provisions, the 

state may allocate allowances to Transport Rule units (whether 

existing or new units) or other entities (such as renewable 

energy facilities) or may auction allowances. EPA will approve 

the full SIP only if the state allocation or auction provisions 

meet certain requirements and all other provisions in the 

Transport Rule trading program in the full SIP are the same as 

those in the Transport Rule FIP trading program. 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. 
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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 proposed TR Annual NOX, TR NOX Ozone-Season, 

TR SO2 Group 1, or TR SO2 Group 2 Trading Program respectively) 

for other states. This will apply 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 Annual NOX

allowance’’, ‘‘TR Ozone-Season NOX 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 Annual NOX

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 program with EPA-approved state allocation and 

auction provisions; and the Transport Rule FIP trading program 

with EPA allocation provisions. Similarly, the definitions in 

the state and Transport Rule FIP trading programs of ‘‘TR OzoneSeason NOX allowance’’, ‘‘TR SO2 Group 1 allowance’’, and ‘‘TR 
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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 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 Annual NOX Trading Program,’’ ‘‘TR Ozone-Season NOX

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 
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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: January 1, 2013 in order to 

govern allowance allocation and auction for control periods in 

2014 and 2015; January 1, 2014 in order to govern control 

periods in 2016 and 2017; January 1, 2015 in order to govern 

allowance allocation and auction for control periods in 2018 and 

2019; and January 1, 2016 and by January 1 of any year 

thereafter in order to govern allowance allocation and auction 

for control periods in the fourth year after such submission 

deadline.

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. In order to replace the FIP in a state, the 
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state’s SIP must provide adequate provisions to prohibit NOX and 

SO2 emissions that contribute significantly to nonattainment or 

interfere with maintenance in another state or states. The 

Transport Rule FIPs remain in place in each covered state until 

a state’s SIP was submitted and approved by EPA to 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 limited to 

allocations made to units that commence commercial operation 

before January 1, 2010 and provided in the form of a list of 
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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 X3, 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 

trade offs 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 [INSERT DATE 70 DAYS AFTER THE DATE OF PUBLICATION 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 units114 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 

 

114 Existing unit means a unit that commences commercial 

operation before January 1, 2010.
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allocations on the list and in any allocation 

previously determined and recorded by the 

Administrator;

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,

o Provides 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 

[INSERT DATE 70 DAYS AFTER THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], EPA will record FIP allocations for 2012 and 

2013 as scheduled (90 days after publication of the 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, EPA will record 

state-determined allocations for 2013 by October 1, 2012. 

Otherwise, EPA will record the EPA-determined allocations for 

2013.
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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

Iowa 37,569

Kansas 30,099

Kentucky 81,683

Maryland 16,300

Michigan 58,989

Minnesota 28,980

Missouri 50,803

Nebraska 24,590

New Jersey 7,121

New York 17,016

North Carolina 47,551

Ohio 90,849

Pennsylvania 117,586

South Carolina 31,849

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
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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

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 Trading Budget available for State 

Allocation in 2013

State Portion of the SO2 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 177,975

Maryland 29,518

Michigan 190,646

Minnesota 41,141

Missouri 203,317

Nebraska 62,450

New Jersey 5,463

New York 20,088

North Carolina 125,930

Ohio 304,025

Pennsylvania 273,078

South Carolina 86,847
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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 SIPs to 

ensure a smooth integration. The Agency will 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 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 Trading Program 

Rules for Limited Interstate Trading

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 Transport Rule Annual NOX trading program, 

Transport Rule Ozone-Season NOX trading program, Transport Rule 

SO2 Group 1 trading program, and Transport Rule SO2 Group 2 
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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 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 and are 

also essentially the same as in prior EPA-administered trading 

programs. However, as discussed in more detail below, some of 
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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 EPA-administered 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 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 

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 fossil-fuel use under the 

solid waste incineration unit exemption (which is discussed 
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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 

fossil-fuel 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). 

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.
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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 commencecommercial-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 continues to 

state that a unit (the replacement unit) that replaces a unit at 

the same source 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” 
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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 

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.

By further example, the final rules clarify the definition 

of “State” by explaining that, by covering each state that is 

subject to the Transport Rule trading program involved, the term 

includes Indian country located within the borders of the state. 

This ensures that units outside of Indian country and within 

Indian country will be treated the same, except in the case of 

the final rule provisions (discussed elsewhere in this preamble) 

concerning the new unit set-aside for Indian country, which is 

expressly limited to Indian country new units. 
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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 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 
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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 rule uses 

2005 (about 5 years before this rule’s promulgation), rather 

than 1990, as the reference year. Consequently, the “fossilfuel-fired” and “cogeneration unit” definitions in the final 

rule specifically reference 2005, rather than 1990. As 

discussed elsewhere in this preamble, consistent with the use of 

2005 as the starting point for applying these definitions, the 

final rule also uses January 1, 2005 (rather than November 15, 

1990) as the reference date in 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 every year starting the later of 2005 or the 12–month 

period starting when the unit begins producing electricity. 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 
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operating and efficiency standards do not have to be met for a 

calendar year throughout which a unit did not operate at all. 

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 Annual NOX

allowance,” “TR Ozone-Season NOX allowance,” “TR SO2 Group 1 

allowance,” “TR SO2 Group 1 allowance,” “TR Annual NOX Trading 

Program,” “TR Ozone-Season NOX 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 (rather than the Administrator) will 
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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, regionwide program with limited interstate trading under which both 

any allowance allocated by the Administrator and any allowance 

allocated by the state 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 

Annual NOX unit,” “TR Ozone-Season NOX 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 
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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 

owner-by-owner basis. 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 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 
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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 

definitions for “coal” and “fuel oil”, 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 the specific states whose electric 

generating units are covered by the respective trading program. 
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Under the general applicability provisions of the proposed 

rules, the Transport Rule trading programs would cover fossilfuel-fired 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 each year thereafter 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 boiler or combustion turbine) must 

operate as part of a “cogeneration system,” which is defined as 

an integrated group of equipment at a source (including a boiler 
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or combustion turbine, and a steam turbine generator) designed 

to produce useful thermal energy for industrial, commercial, 

heating, or cooling purposes and electricity through the 

sequential use of energy. 

 In order to qualify as a cogeneration unit, a unit also must 

meet, on 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. 

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 each year thereafter, 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 
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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 each year 

thereafter, 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 

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 
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preamble) if the state’s total covered-unit emissions exceed the 

state assurance level. 

Specifically, a 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 would 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 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 
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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 a 

designated representative, instead of being implemented on an 

owner-by-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 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 
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deduction through the transfer of such allowances to the 

assurance account created by the Administrator for such owners 

and operators) is determined on a designated representative 

basis. 

For purposes of implementing the assurance provisions, 

covered units in a state are in effect grouped by designated 

representative (as distinguished from the alternate designated 

representative). The control period emissions of all covered 

units with the same 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 

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 in each group 

must transfer to the assurance account created for such owners 

and operators a total amount of allowances equal to such owners’ 

and operators’ proportionate share of the state’s excess of 

covered-unit emissions over the state trading budget plus 

variability. 

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 
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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 designated-representative-based 

approach. For example, as discussed elsewhere in this preamble, 

these provisions use the terms, “designated representative’s 

share” and “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 “designated representatives” 

and “owners and operators,” rather than simply “owners.”

The final rules also clarify the standard emissions 

requirements by explaining further what is meant by the 

provision that an allowance is a limited authorization to emit. 

The final rule clarifies 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, an 
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allowance provides an emission authorization that can only be 

used in accordance with the requirements of the respective 

Transport Rule 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, 

the authorization to emit that is provided by an allowance will 

not necessarily remain unchanged in the future. Under the final 

rules, the Administrator has the express authority to terminate 

or limit the authorization 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 the same in the final rules as in the proposed 

rules.
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(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 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 
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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 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, and variability limits. 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 
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tables in the proposed rules. The final rule values reflect the 

determinations and modeling underlying the final rules and 

discussed elsewhere in this preamble.

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 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 two 

consecutive years starting in 2012. In that case, the unit 

continues to receive its existing unit allocation for those 

years plus only two 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 three consecutive years 
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would continue to receive its existing unit allocation for those 

years plus three 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. 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 
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to 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 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 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 
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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 difference 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 is 

insufficient to provide this initial allocation for all of the 

second round units, then each such unit is allocated its 

proportionate share of the allowances remaining in the new unit 

set-aside. The Administrator uses notices of data availability 
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(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 units in the second round allocations and 

obtain and consider any objections and to 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 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 
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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, with one 

exception. The exception is where the determination of 

compliance with the emission limitation 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 unit) that receives an allocation but is 

not actually a covered unit. However, under the final rules, 
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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’ 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 
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required to certify their monitoring systems and hold allowances 

covering emissions starting January 1, 2012. The 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 the 

essentially 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 
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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 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, 
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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 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 
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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 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 
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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. 

(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 
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of allowances transferred. 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 

emissions limitations must be held. The designated 

representative and alternate for the source is also 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 
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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 allowance allocations for existing units, as set forth in 

a required notice of data availability, for the Transport Rule 

annual NOX, ozone-season 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 revisions 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 Statedetermined existing-unit allocations for 2013, and, in the 
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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 State-determined) 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 existingunit 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. 

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 
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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 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 (referred to as the vintage year) for which the 

allocations are made. 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. 

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 two years (i.e., 
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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 May 1, 2012. Complete abbreviated and full 

SIPs must be submitted to the Administrator by: January 1, 2013 

in order to govern allowance allocation and auction for control 

periods in 2014 and 2015; January 1, 2014 in order to govern 

control periods in 2016 and 2017; January 1, 2015 in order to 

govern allowance allocation and auction for control periods in 

2018 and 2019; and January 1, 2016 and by January 1 of any year 

thereafter in order to govern allowance allocation and auction 

for control periods in the fourth year after 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 

emissions data from the control period in the prior year), to 
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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 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 
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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 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, then the owners and operators must provide, for 

deduction by the Administrator, two allowances allocated for the 

control period in the next year for every allowance that the 

owners and operators failed to hold as required to cover 

emissions. In addition, the owners and operators are subject to 

discretionary civil penalties for each violation. 
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(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 owners 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 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 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 
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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 designated-representativebased process is more streamlined than the owner-based process 

in the proposed rules.

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 one-year variability limit. As discussed 

elsewhere in this preamble, EPA decided not to use a three-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 May 1, 2013 and May 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 May 1 

notice of data availability as having emissions exceeding the 

state trading budget with variability, the designated 
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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 May 1 notice of data availability and for each 

common designated representative of a group of units (which 

groups can include one or more units and sources) in the state, 

the designated representative’s share of emissions, the 

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 

designated representative (which groups can include one or more 

owners and operators) in the state must surrender under the 

assurance provisions (i.e., the 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 
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availability of the results of these calculations, provides an 

opportunity for submission of objections, and promulgates by 

October 1 a second notice of 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 May 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 May 1 and 

August 1 notices, rather than two separate opportunities, one 

for each notice.

Also in contrast with the proposed rules, the deadlines for 

issue 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 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 August 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 
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determined in the August 1 notice of data availability. Where 

the August 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 Acid Rain Program).

As part of implementing the designated-representative-based 

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 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 assurance accounts established by 

the owners), there is no need for the proposed rule provisions 

concerning identification of which allowances are to be deducted 
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and first-in, first-out deduction in the absence of such 

identification. 

The final Transport Rule provides that, in general, the 

surrender amounts specified in the August 1 notice for owners 

and operators are final and will not be revised even if the 

underlying data (e.g., emissions data) used in the calculations 

underlying the August 1 notice are subsequently revised. 

However, the final rule sets 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 August 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 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 August 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 
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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 an owner or operator to become subject 

to the allowance surrender requirement under the assurance 

provisions. However, the failure of any owner or operator or 

group of two or more 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 
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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, 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 
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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 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 
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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) 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.

XII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review
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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 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 
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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, 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 
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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 

emissions 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.C1 and VIII.C-2 of this preamble. When characterizing 

uncertainty in the 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 concentrationresponse relationship. In the RIA accompanying this rulemaking, 
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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 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 
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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 Rule and estimates the incremental costs of 
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compliance with all such requirements, such as the requirement 

for industry to monitor, record, and report emissions 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 emissions 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 EPA-administered 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 emissions limits and other requirements. Such 

records and reports are also helpful to EPA and states in both 
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identifying affected facilities that may not be in compliance 

with applicable requirements 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 Ruleaffected sources in states participating in the Transport Rule 

trading program 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 

program is approximately 185,000 hours annually. These 

estimates include the annualized cost of installing and 

operating appropriate SO2 and NOX emissions monitoring equipment 

to measure and report the total emissions of these pollutants 

from affected EGUs (serving generators greater than 25 megawatt 

electrical). The burden to state and local air agencies, 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 
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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 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:
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(1) A small business as defined by the Small Business 

Administration’s (SBA) regulations at 13 CFR 121.201. For the 

electric power generation industry, the small business size 

standard is an ultimate parent entity defined as having a total 

electric output of 4 million megawatt-hours (MW-hour) or less in 

the previous fiscal year.

(2) A small governmental jurisdiction that is a government 

of a city, county, town, school district or special district 

with a population of less than 50,000; and

(3) A small organization that is any not-for-profit 

enterprise which is independently owned and operated and is not 

dominant in its field. 

Table XII.C-1 — Potentially Regulated Categories and 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 
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Country.

a Include NAICS categories for source categories that own and 

operate electric generating units only.

b North American Industry Classification System.

c Federal, state, or local government-owned and operated 

establishments are classified according to the activity in which 

they are engaged.

After considering the economic impacts of this 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 4MM MWh) out of 

3,625 existing units in the TR region. 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. This is 

compared to 30 of 81 potentially affected small entities that 

EPA projected in the proposal would have annualized costs 
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greater than 1 percent of their revenues and 51 entities 

projected to incur costs less than 1 percent of revenues. While 

the total number of small entities has increased 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 the percentage of significantly impacted small 

entities (costs greater than 3 percent of revenues) is also 

slightly lower. 

EPA received a small number of comments regarding its 

economic impact analysis for small entities and expressed 

disagreement with EPA’s finding of No SISNOSE. Commenters did 

not provide adequate information to refute EPA’s analysis or 

demonstrate that this final rule would likely impact a greater 

number of small entities. EPA acknowledges that it anticipates 

some small entities will experience increased costs under this 

final rule, but that it does not expect the number to be 

substantial. 

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, 
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driving the bulk of the costs for all small entities. Excluding 

these two units, one of the main drivers of small entity impacts 

are higher fuel costs, which the affected units would incur 

irrespective of whether they had to comply with this rule. In 

addition, EPA’s decision to exclude units smaller than 25 MWe 

has already significantly reduced the burden on small entities. 

Hence, EPA has concluded that there is no SISNOSE for this rule.

For more information on the small entity impacts associated 

with the final rule, please refer to the Regulatory Impact 

Analysis for this final rule. 

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 one 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 
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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 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 

for EGUs constructed in Indian country provision to this final 

rule 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 final remedy of limited 

interstate 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 
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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 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 
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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 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 

Notice of Data Availability (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 
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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. 

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.
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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 12 additional tribes 

and representatives from the National Tribal Air Association. In 

all ten tribes participated in these calls as consultation and 

five participated as information-sharing. EPA considered the 

additional 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
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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.

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 
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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 
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energy action.” This rule is a significant regulatory action 

under Executive Order 12866, and this 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 price 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 
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the type of coal demanded. EPA also projects that electric 

power sector-delivered natural gas price will increase by about 

0.3% over the 2012-2030 timeframe and that natural gas use for 

electricity generation will increase by 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% 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 
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on energy supply. Second, the more stringent budgets for SO2 are 

set in two phases, providing adequate time for EGUs to install 

pollution controls. In addition, both the operational 

flexibility of trading and the ability to bank allowances for 

future years helps industry plan for and ensure reliability in 

the electrical system.

For more details concerning energy impacts, see the RIA for the 

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. 
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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, 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 
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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, low-income, 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 

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 simultaneously with this final 

rule 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. 
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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 the 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 SO2

and nitrogen oxide NOX pollution that significantly 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 currently meet the NAAQS but 
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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 a limited emissions trading mechanism with 

assurance provisions for power plants. EPA recognizes that many 

environmental justice communities have voiced concerns in the 

past about emissions trading and the potential for any emissions

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 emissions sources – is due to 

emissions from nearby sources and part is due to emissions that 

travel hundreds of miles and mix with emissions from other 

sources. Therefore, in many instances the exact location of the 

upwind reductions does not affect the levels of air pollution 

downwind. 

It is important to 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 
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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 reduced but each facility could emit 

more by increasing their power output in order to meet 

electricity reliability or other goals. Under the intrastate 

trading option, state emissions would have stayed constant but 

individual facilities within each state could have increased 

their emissions as long as another facility in the state had 

decreased theirs.

The rule tightly constrains the influence of emission 

trading by requiring a strict emission ceiling in each state 

(the budget plus variability limit) while allowing limited 

ability to trade emissions between facilities or states. 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 

contributes to downwind nonattainment or maintenance areas, 

while allowing power companies to adjust generation as needed 

and ensure that the country’s electricity needs will continue to 
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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 the 

excess, or the source itself had used 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 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; limiting the amount of 

interstate trading possible; 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 
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rule 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 set-asides. 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 

federal implementation plan (FIP) or state implementation plan 

(SIP). While there are no existing power plants in Indian 

country covered by this Transport Rule, the Indian country setasides 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 
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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 raised by the 

Court’s opinion in North Carolina that remanded the Clean Air 

Interstate Rule (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 
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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.

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 

fine particle (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 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 
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populations, including those susceptible and vulnerable to air 

pollution health impacts.

a. Emission reductions

EPA’s emissions 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 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 
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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 region due to the interconnected nature of the 

utility grid (i.e., shifts in generation of electricity to 

sources outside the Transport Rule region) 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 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 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 

significant additional SO2 emission reductions, including in 

states not covered by the Transport Rule.
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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 lowemitting year and sources are projected to increase their heat 

input slightly (usually meaning they are generating more power) 

after the rule takes effect. 

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 ozone-season NOX emissions from EGUs in both covered 

states and non-Transport Rule states under this rule will be 

lower than they would have been in 2014 in the base case. 

Seasonal NOX emissions in covered states are projected to 

decrease by approximately 74,000 tons (11 percent); seasonal 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 
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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 values are projected to improve over 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 
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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 are 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 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 
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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 region: 

one county in northern Colorado and one county in eastern 

Montana. As 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 low-sulfur coal market. It 
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should be noted that 2003-2007 average air quality levels in 

these counties is well below the level of the NAAQS and that it 

does get even cleaner under the final rule. 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 longrange 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, lowincome, 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 these pollutants can cause 
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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)115 and asthma116

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 illnesses117.

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 

 

115 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.

116 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.

117R. Nelson, Eds. National Institute of Medicine, 2003.
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children in the form of fewer cases of upper and lower 

respiratory illness, acute bronchitis, and asthma attacks.

Ozone health-related benefits are expected to occur during 

the summer ozone season (usually ranging from May to September

in the eastern U.S.). Based upon modeling for 2014, annual 

ozone related health benefits are expected to include (in 

addition to the PM-related 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 to 34,000 

fewer premature mortalities. 

It should be noted that, as discussed in the RIA, that 

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. 
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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 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 colleagues118 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. It should be noted that, due to timing constraints, 

this analysis used air quality and benefits data from the 

 

118 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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proposed Transport Rule. However, the air quality modeling 

results for this final rule indicate that the geographic 

distribution of air quality improvements is very similar to 

those projected in modeling for the proposed Transport Rule. As 

a result, we expect this distributional analysis to be a 

reasonable estimate of the effects of this final rule. 

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 and the highest (top 5 

percent) poverty rate in 2005. We also 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 estimated the changes in risk for different 

races among the people living in these “high-risk” and “highpoverty” 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-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 poorest counties had substantially higher risks of PM2.5-

related death than people living in the other 95 percent of 
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counties. This was true regardless of race: the differences 

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 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 mortality rate 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 
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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 poorest 5 

percent of counties will experience somewhat smaller 

improvements in risk from this Transport Rule alone compared to 

their counterparts in the other 95 percent of counties. This is 

due to the fact that many of the counties with the highest 

levels of poverty are in areas outside the Transport Rule region 

and therefore experience little to no emission reductions as a 

result of the rule. There is little difference in the 

improvement in risk among races; in other words, people in the 

poorest 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 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 
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levels. In addition, implementation of this Transport Rule and 

other rules will, together, reduce risks in the poorest 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-OAR-2009-0491 and from the main EPA webpage for the 

rule 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 prior to the formal start of the 
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rulemaking process. These stakeholders included a number of 

environmental groups who requested that EPA consider several 

potential environmental justice issues during development of 

this rule. In addition, many environmental justice 

organizations were represented at a November 2009 EPA-Health and 

Human Services White House Stakeholder Briefing entitled “The 

Public Health Benefits of Energy Reform” in which EPA discussed 

our intention to propose this rule in the spring of 2010 and 

participants had the opportunity to respond. Finally, EPA 

notified 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 wellattended 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.
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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. 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 formal consultation and information-sharing calls 

with 14 interested Tribes in late January and early February 

2011. Tribes participating on these consultation and information 
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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

EPA believes that the vast majority of communities and 

individuals in areas covered by this rule, including numerous 

low-income, 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 show evidence of adverse effects. As a 

result, EPA concludes that we do not expect disproportionately 
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high and adverse human health or environmental effects on 

minority, low-income, 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 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].

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]. Section 307(b)(1) of the CAA indicates which 
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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.’’

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 
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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.

 
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Federal Implementation Plans to Reduce Interstate

Transport of Fine Particulate Matter and

Ozone (Page 628 of 1339)

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 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.

DATE:________________________

______________________________

Lisa P. Jackson,

Administrator.

For the reasons set forth in the preamble, parts 51, 52, 72, 78, 

and 97 of chapter I of title 40 of the Code of Federal 

Regulations are amended as follows:

PART 51—[AMENDED]
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1. The authority citation for Part 51 continues to read as 

follows:

Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q

§ 51.121 [Amended]

2. Section 51.121 is amended by revising paragraph (r)(2) by 

removing the words “§51.123(bb)” and adding, in their place, the 

words “§51.123(bb) with regard to an ozone season that occurs 

before January 1, 2012”. 

§ 51.123 [Amended]

3. Section 51.123 is amended by adding a new paragraph (ff) to 

read as follows: 

§ 51.123 Findings and requirements for submission of State 

implementation plan revisions relating to emissions of oxides of 

nitrogen pursuant to the Clean Air Interstate Rule.

* * * * *

(ff) Notwithstanding any provisions of paragraphs (a) through 

(ee) of this section, subparts AA through II and AAA through III 

of part 96 of this chapter, subparts AA through II and AAAA 

through IIII of part 97 of this chapter, and any State’s SIP to 

the contrary:
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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 surrender or deduction of such allowances 

for excess emissions in any control period will be required; 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 surrender or deduction of 

such allowances for excess emissions in any control period will 

be required.

§ 51.124 [Amended]

4. Section 51.124 is amended by adding a new paragraph (s) to 

read as follows: 

§ 51.124 Findings and requirements for submission of State 

implementation plan revisions relating to emissions of sulfur 

dioxide pursuant to the Clean Air Interstate Rule. 

* * * * *

(s) Notwithstanding any provisions of paragraphs (a) through (r) 

of this section, subparts AAA through III of part 96 of this 

chapter, subparts AAA through III of part 97 of this chapter, 

and any State’s SIP to the contrary: 

(1) With regard to any control period that begins after December 

31, 2011, the Administrator:
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(i) Rescinds the determination in paragraph (a) of this section 

that the States identified in paragraph (c) of this section must 

submit a SIP revision with respect to the fine particles (PM2.5) 

NAAQS meeting the requirements of paragraphs (b) through (r) of 

this section; and 

(ii) Will not carry out any of the functions set forth for the 

Administrator in subparts AAA through III of part 96 of this 

chapter, subparts AAA through III of part 97 of this chapter, or 

in any emissions trading program in a State’s SIP approved under 

this section; and

(2) The Administrator will not deduct for excess emissions any 

CAIR SO2 allowances allocated for 2012 or any year thereafter.

§ 51.125 [Reserved]

5. Section 51.125 is removed and reserved. 

PART 52—[AMENDED]

6. The authority citation for Part 52 continues to read as 

follows:

Authority: 42 U.S.C. 7401, et seq.

Subpart A—General Provisions

§ 52.35 [Amended]
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7. Section 52.35 is amended by adding a new paragraph (f) to 

read as follows: 

§ 52.35 What are the requirements of the Federal Implementation Plans 

(FIPs) for the Clean Air Interstate Rule (CAIR) relating to emissions 

of nitrogen oxides?

* * * * * 

(f) Notwithstanding any provisions of paragraphs (a) through (d) 

of this section, subparts AA through II and AAAA through IIII of 

part 97 of this chapter, and any State’s SIP to the contrary: 

(1) With regard to any control period that begins after December 

31, 2011,

(i) The provisions in paragraphs (a) through (d) of this section 

relating to NOX annual or ozone season emissions shall not be 

applicable; and

(ii) The Administrator will not carry out any of the functions 

set forth for the Administrator in subparts AA through II and 

AAAA through IIII of part 97 of this chapter; 

(2) The Administrator will not deduct for excess emissions any 

CAIR NOX allowances or CAIR NOX Ozone Season allowances allocated 

for 2012 or any year thereafter;
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(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 surrender or deduction of such allowances 

for excess emissions in any control period will be required; 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 surrender or deduction of 

such allowances for excess emissions in any control period will 

be required.

§ 52.36 [Amended]

8. Section 52.36 is amended by adding a new paragraph (e) to 

read as follows: 

§ 52.36 What are the requirements of the Federal Implementation Plans 

(FIPs) for the Clean Air Interstate Rule (CAIR) relating to emissions 

of sulfur dioxide?

* * * * *
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(e) Notwithstanding any provisions of paragraphs (a) through (c) 

of this section, subparts AAA through III of part 97 of this 

chapter and any State’s SIP to the contrary: 

(1) With regard to any control period that begins after December 

31, 2011,

(i) The provisions of paragraphs (a) through (e) of this section 

relating to SO2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions 

set forth for the Administrator in subparts AAA through III of 

part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any 

CAIR SO2 allowances allocated for 2012 or any year thereafter.

9. Subpart A is amended by adding §§52.37 and 52.38 to read as 

follows: 

§ 52.37 What are the requirements of the Federal Implementation Plans 

(FIPs) under the Transport Rule (TR) relating to emissions of nitrogen 

oxides? 

(a)(1) The TR NOX Annual Trading Program provisions of part 97 of this 

chapter constitute the TR Federal Implementation Plan provisions that 

relate to annual emissions of nitrogen oxides (NOX). 
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(2) The provisions of subpart AAAAA of part 97 of this chapter, 

regarding the TR NOX Annual Trading Program, apply to the sources in 

the following States: Alabama, Georgia, Illinois, Indiana, Iowa, 

Kansas, Kentucky, Maryland, Michigan, Minnesota, Missouri, Nebraska, 

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

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

(3) Notwithstanding the provisions of paragraph (a)(1) of this 

section, a State listed in paragraph (a)(2) 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) 

with regard to the control period in 2013, a list of TR NOX Annual 

units and the amount of TR NOX Annual 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 Annual allowance allocations on the 

list must not exceed the amount of the State’s TR NOX Annual trading 

budget minus the sum of the amounts of the State’s new unit set-aside 

and Indian country new unit set-aside for 2013 under §97.410(a); 

(iii) The list must be submitted electronically in a format specified 

by the Administrator; and
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(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 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 (a)(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 (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) may adopt and include in a 

SIP revision, and the Administrator will approve, regulations revising 

the TR NOX Annual Trading Program as follows and not making any other 

substantive revisions of the TR NOX Annual Trading Program:

(i) The State may adopt, as TR NOX Annual allowance allocation 

provisions replacing the provisions in §§97.411(a) and (b) and 
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97.412(a) with regard to the control period in 2014 and thereafter, 

provisions substantively identical to those provisions, except that 

the State or the permitting authority allocates in lieu of the 

Administrator; or 

(ii) The State may adopt, as TR NOX Annual allowance allocation or 

auction provisions replacing the provisions in §§97.411(a) and (b) and 

97.412(a) with regard to the control period in 2014 and thereafter, 

any methodology under which the State or the permitting authority 

allocates in lieu of the Administrator or auctions TR NOX Annual 

allowances, and may adopt, in addition to the definitions in §97.402, 

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 that the total amount of TR NOX Annual allowances 

allocated and, if applicable, auctioned by the State or the permitting 

authority for such control period not exceed the amount of the State’s 

TR NOX Annual trading budget, minus the amounts of the State’s Indian 

country new unit set-aside and of TR NOX Annual allowances already 

allocated and recorded by the Administrator, for such control period.

(B) Requires, to the extent the State adopts provisions for 

allocations to or auction of TR NOX Annual allowances for any TR NOX

Annual units covered by §97.411(a) for any such control period, that 

the State or the permitting authority submit such allocations or the 
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results of such auction for such control period (except allocations to 

or auctions for such units of TR NOX Annual allowances remaining 

unallocated or not auctioned in a set-aside for recipients other than 

such units after completion of such allocations or auctions) 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 to or auctions of TR NOX Annual allowances for any TR NOX

Annual units covered by §§97.411(b)(1) and 97.412(a), that the State 

or the permitting authority submit such allocations or the results of 

such auction (except allocations to or auctions for such units of TR 
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NOX Annual allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 

auctions) 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)(3)(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 AAAAA of part 97 of this chapter; ;

(iii) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (a)(4)(i) or (ii) of this 

section by December 1 of the year before the year of the deadline for 

submission of allocations or auction results under paragraphs 

(a)(4)(ii)(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) or (ii) of this section.

(5) Notwithstanding the provisions of paragraph (a)(1) of this 

section, a State listed in paragraph (a)(2) may adopt and include in a 

SIP revision, and the Administrator will approve, as correcting the 

deficiency in the SIP that is the basis for the TR Federal 

Implementation Plan set forth in paragraphs (a)(1) through (3) of this 

section, regulations thatare substantively identical to the TR NOX 
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Annual Trading Program set forth in §§97.402 through97.435, except 

that the SIP revision may:

(i) Adopt, as TR NOX Annual allowance allocation provisions replacing 

the provisions in §§97.411(a) and (b) and 97.412(a) with regard to the 

control period in 2014 and thereafter, provisions substantively 

identical to those provisions, except that the State or the permitting 

authority allocates in lieu of the Administrator; or 

(ii) Adopt, as TR NOX Annual allowance allocation or auction provisions 

replacing the provisions in §§97.411(a) and (b) and 97.412(a) with 

regard to the control period in 2014 and thereafter, any methodology 

under which the State or the permitting authority allocates in lieu of 

the Administrator 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 the 

control period not exceeding the amount of the State’s TR NOX Annual 

trading budget minus the amounts of the State’s Indian country new 

unit set-aside and of TR NOX Annual allowances already allocated and 

recorded by the Administrator, for such control period.

(B) Requires, to the extent the State adopts provisions for 

allocations or auction of TR NOX Annual allowances for any TR NOX

Annual units covered by §97.411(a) for any control period starting in 

2014, that the State or the permitting authority submit such 
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allocations or the results of such auction for such control period 

(except allocations to or auctions for such units of TR NOX Annual 

allowances remaining unallocated or not auctioned in a set-aside for 

recipients other than such units after completion of such allocations 

or auctions) 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 auction of TR NOX Annual allowances for any TR NOX

Annual units covered by §97.411(a) for any control period in 2020 and 

any year thereafter, that the State or the permitting authority submit 

such allocations or the results of such auction (except allocations to 

or auctions for such units of TR NOX Annual allowances remaining 
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unallocated or not auctioned in a set-aside for any recipients after 

completion of such allocations or auctions) to the Administrator no 

later than June 1 of the fourth year before the year of such control 

period.

(D) Requires, to the extent the State adopts provisions for 

allocations or auctions of TR NOX Annual allowances for any TR NOX

Annual units covered by §§97.411(b) and 97.412(a), that the State or 

the permitting authority submit such allocations or the results of 

such auction (except allocations to or auctions for such units of TR 

NOX Annual allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 

auctions) to the Administrator by July 1 of the year of such control 

period.

(E) Does not provide for any change, after the submission deadlines in 

paragraphs (a)(3)(ii)(B), (C), and (D) 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.

(iii) Provided that the State may adopt, in addition to the 

definitions in §97.402, 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)(4)(ii) of this section; and
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(iv) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (a)(4)(i) or paragraphs 

(a)(4)(ii) and (4)(iii) of this section by December 1 of the year 

before the year of the deadline for submission of allocations or 

auction results under paragraphs (a)(4)(ii)(B) and (C) of this section 

applicable to the first control period for which the State wants to 

make such allocations or hold such auction under paragraph (a)(4)(i) 

or paragraphs (a)(4)(ii) and (4)(iii) of this section. 

(6) Following promulgation of an approval by the Administrator of a 

State's SIP revision as correcting the SIP’s deficiency that is the 

basis for the TR Federal Implementation Plan described in paragraphs 

(a)(1) through (4) 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.

(7) Notwithstanding the provisions of paragraph (a)(5) of this 

section, if, at the time of such approval of the State's SIP revision, 

the Administrator has already allocated any TR NOX Annual allowances to 

sources in the State for any years, the provisions of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

NOX Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision.

(b)(1) The TR NOX Ozone Season Trading Program provisions of part 97 of 
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this chapter constitute the TR Federal Implementation Plan provisions 

that relate to emissions of NOX during the ozone season, defined as May 

1 through September 30 of a calendar year. 

(2) The provisions of subpart BBBBB of part 97 of this chapter, 

regarding the TR NOX Ozone Season Trading Program, apply to sources in 

each of the following States: Alabama, Arkansas, 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) 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) with regard to 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 of the State’s TR NOX Ozone Season 

trading budget minus the sum of the amounts of the State’s new unit 
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Page 646 of 1339

set-aside and Indian country new unit set-aside for 2013 under 

§97.510(a); 

(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) may adopt and include in a 

SIP revision, and the Administrator will approve, regulations revising 
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the TR NOX Ozone Season Trading Program as follows and not making any 

other substantive revisions of the TR NOX Ozone Season Trading Program:

(i) The State may adopt, as applicability provisions replacing the 

provisions in §§97.504(a)(1) and (2), provisions substantively 

identical to those provisions, except that the words “25 MWe” are 

replaced in each place where such words appear by an uniform amount of 

megawatts that is less than 25 MWe and not less than 15 MWe; 

(ii) The State may adopt, as TR NOX Ozone Season allowance allocation

provisions replacing the provisions in §§97.511(a) and (b) and 

97.512(a) with regard to the control period in 2014 and thereafter, 

provisions substantively identical to those provisions, except that 

the State or the permitting authority allocates in lieu of the 

Administrator; or 

(iii) The State may adopt, as TR NOX Ozone Season allowance allocation 

or auction provisions replacing the provisions in §§97.511(a) and (b) 

and 97.512(a) with regard to the control period in 2014 and 

thereafter, any methodology under which the State or the permitting 

authority allocates in lieu of the Administrator or auctions TR NOX

Ozone Season allowances, and may adopt, in addition to the definitions 

in §97.502, 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--
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(A) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR NOX Ozone Season allowances 

for the control period not exceeding the amount of the State’s TR NOX

Ozone Season trading budget minus the amounts of the State’s Indian 

country new unit set-aside and of TR NOX Ozone Season allowances 

already allocated and recorded by the Administrator, for such control 

period.

(B) Requires, to the extent the State adopts provisions for 

allocations or auction of TR NOX Ozone Season allowances for any TR NOX

Ozone Season units covered by §97.511(a) for any control period 

starting in 2014, that the State or the permitting authority submit 

such allocations or the results of such auction for such control 

period (except allocations to or auctions for such units of TR NOX

Ozone Season allowances remaining unallocated or not auctioned in a 

set-aside for recipients other than such units after completion of 

such allocations or auctions) to the Administrator no later than the 

following dates:

Year of the 

control period 

for which TR 

NOX Ozone 

Sesaon 

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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Page 649 of 1339

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 auction of TR NOX Ozone Season allowances for any TR NOX

Ozone Season units covered by §97.511(a) for any control period in 

2020 and any year thereafter, that the State or the permitting 

authority submit such allocations or the results of such auction 

(except allocations to or auctions for such units of TR NOX Ozone 

Season allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 

auctions) to the Administrator no later than June 1 of the fourth year 

before the year of such control period.

(D) Requires, to the extent the State adopts provisions for 

allocations or auctions of TR NOX Ozone Season allowances for any TR 

NOX Ozone Season units covered by §§97.511(b) and 97.512(a), that the 

State or the permitting authority submit such allocations or the 

results of such auction (except allocations to or auctions for such 

units of TR NOX Ozone Season allowances remaining unallocated or not 

auctioned in a set-aside for any recipients after completion of such 
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Page 650 of 1339

allocations or auctions)to the Administrator by July 1 of the year of 

such control period. 

(E) Does not provide for any change, after the submission deadlines in 

paragraphs (b)(3)(ii)(B), (C), and (D) 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; 

(iv) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (b)(3)(i), (ii), or (iii) of 

this section by December 1 of the year before the year of the deadline 

for submission of allocations or auction results under paragraphs 

(3)(ii)(B) and (C) of this section applicable to the first control 

period for which the State wants to replace the applicability 

provisions, make such allocations, or hold such auction under 

paragraph (b)(3)(ii) or (iii) of this section.

(5) Notwithstanding the provisions of paragraph (b)(1) of this 

section, a State listed in paragraph (a)(2) may adopt and include in a 

SIP revision, and the Administrator will approve, as correcting the 

deficiency in the SIP that is the basis for the TR Federal 

Implementation Plan set forth in paragraphs (b)(1) through (3) of this 

section, regulations that are substantively identical to the TR NOX
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Page 651 of 1339

Ozone Season Trading Program set forth in §§97.502 through 97.535, 

except that the SIP revision may:

(i) Adopt, as applicability provisions replacing the provisions in 

§§97.504(a)(1) and (2), provisions substantively identical to those 

provisions, except that the words “25 MWe” are replaced in each place 

where such words appear by an uniform amount of megawatts that is less

than 25 MWe and not less than 15 MWe; 

(ii) Adopt, as TR NOX Ozone Season allowance allocation provisions 

replacing the provisions in §§97.511(a) and (b) and 97.512(a) with 

regard to the control period in 2014 and thereafter, provisions 

substantively identical to those provisions, except that the State or 

the permitting authority allocates in lieu of the Administrator; or 

(iii) Adopt, as TR NOX Ozone Season allowance allocation provisions 

replacing the provisions in §§97.511(a) and (b) and 97.512(a) with 

regard to the control period in 2014 and thereafter, any methodology 

under which the State or the permitting authority allocates in lieu of 

the Administrator or 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 the control period not exceeding the amount of the State’s TR NOX

Ozone Season trading budget minus the amounts of the State’s Indian 

country new unit set-aside and of TR NOX Ozone Season allowances 
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Page 652 of 1339

already allocated and recorded by the Administrator, for such control 

period.

(B) Requires, to the extent the State adopts provisions for 

allocations or auction of TR NOX Ozone Season allowances for any TR NOX

Ozone Season units covered by §97.511(a) for any control period 

starting in 2014, that the State or the permitting authority submit 

such allocations or the results of such auction for such control 

period (except allocations to or auctions for such units of TR NOX

Ozone Season allowances remaining unallocated or not auctioned in a 

set-aside for recipients other than such units after completion of 

such allocations or auctions) to the Administrator no later than the 

following dates:

Year of the 

control period 

for which TR 

NOX Ozone 

Sesaon 

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 June 1 of the 
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Page 653 of 1339

year 

thereafter

fourth year 

before the 

year of the 

control period

(C) Requires, to the extent the State adopts provisions for 

allocations or auction of TR NOX Ozone Season allowances for any TR NOX

Ozone Season units covered by §97.511(a) for any control period in 

2020 and any year thereafter, that the State or the permitting 

authority submit such allocations or the results of such auction 

(except allocations to or auctions for such units of TR NOX Ozone 

Season allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 

auctions) to the Administrator no later than June 1 of the fourth year 

before the year of such control period.

(D) Requires, to the extent the State adopts provisions for 

allocations or auctions of TR NOX Ozone Season allowances for any TR 

NOX Ozone Season units covered by §§97.511(b) and 97.512(a), that the 

State or the permitting authority submit such allocations or the 

results of such auction (except allocations to or auctions for such 

units of TR NOX Ozone Season allowances remaining unallocated or not 

auctioned in a set-aside for any recipients after completion of such 

allocations or auctions)to the Administrator by July 1 of the year of 

such control period. 

(E) Does not provide for any change, after the submission deadlines in 

paragraphs (b)(4)(ii)(B) and (C) of this section, in the allocations 
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Page 654 of 1339

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;

(iv) Provided that the State may also adopt, in addition to the 

definitions in §97.502, 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)(4)(iii) of this 

section; and

(v) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (b)(4)(i), (ii), or (iii) of 

this section by December 1 of the year before the year of the deadline 

for submission of allocations or auction results under paragraphs 

(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 such allocations, or hold such auction under 

paragraph (b)(4)(ii) or (iii) of this section. 

(6) Following promulgation of an approval by the Administrator of a 

State's SIP revision as correcting the SIP’s deficiency that is the

basis for the TR Federal Implementation Plan set forth in paragraphs 

(b)(1) through (4) 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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Page 655 of 1339

conditional. 

(7) Notwithstanding the provisions of paragraph (b)(5) of this 

section, if, at the time of such approval of the State's SIP revision, 

the Administrator has already allocated any TR NOX Ozone Season 

allowances to sources in the State for any years, the provisions of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Ozone Season allowances for those years shall 

continue to apply, unless provided otherwise by such approval of the 

State’s SIP revision. 

§ 52.38 What are the requirements of the Federal Implementation Plans 

(FIPs) for the Transport Rule (TR) relating to emissions of sulfur 

dioxide?

(a) The TR SO2 Group 1 Trading Program and TR SO2 Group 2 Trading 

Program provisions of part 97 of this chapter constitute the TR

Federal Implementation Plan provisions that relate to emissions of 

sulfur dioxide (SO2). 

(b) The provisions of subpart CCCCC of part 97 of this chapter, 

regarding the TR SO2 Group 1 Trading Program, apply to sources in each 

of the following States: 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, 

regarding the TR SO2 Group 2 Trading Program, apply to sources in each 

of the following 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) 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) with 

regard to 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 of the State’s TR SO2 Group 1 trading 

budget minus the sum of the amounts of the State’s new unit set-aside 

and Indian country new unit set-aside for 2013 under §97.610(a); 

(3) The list must be submitted electronically in a format specified by 

the Administrator; and
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Page 657 of 1339

(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 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) may adopt and include in a SIP revision, 

and the Administrator will approve, regulations revising the TR SO2

Group 1 Trading Program as follows and not making any other 

substantive revisions of the TR SO2 Group 1 Trading Program:

(1) The State may adopt, as TR SO2 Group 1 allowance allocation 

provisions replacing the provisions in §§97.611(a) and (b) and 
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Page 658 of 1339

97.612(a) with regard to the control period in 2014 and thereafter, 

provisions substantively identical to those provisions, except that 

the State or the permitting authority allocates in lieu of the 

Administrator; or 

(2) The State may adopt, as TR SO2 Group 1 allowance allocation 

provisions replacing the provisions in §§97.611(a) and (b) and 

97.612(a) with regard to the control period in 2014 and thereafter, 

any methodology under which the State or the permitting authority 

allocates in lieu of the Administrator or auctions TR SO2 Group 1 

allowances and may adopt, in addition to the definitions in §97.602, 

one or more definitions that 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 1allowances for the 

control period not exceeding the amount of the State’s TR SO2 Group 1 

trading budget minus the amounts of the State’s Indian country new 

unit set-aside and of TR SO2 Group 1 allowances already allocated and 

recorded by the Administrator, for such control period.

(ii) Requires, to the extent the State adopts provisions for 

allocations or auction of TR SO2 Group 1 allowances for any TR SO2

Group 1 units covered by §97.611(a) for any control period starting in 

2014, that the State or the permitting authority submit such 
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Page 659 of 1339

allocations or the results of such auction for such control period 

(except allocations to or auctions for such units of TR SO2 Group 1 

allowances remaining unallocated or not auctioned in a set-aside for 

recipients other than such units after completion of such allocations 

or auctions) 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 auction of TR SO2 Group 1 allowances for any TR SO2

Group 1 units covered by §97.611(a) for any control period in 2020 and 

any year thereafter, that the State or the permitting authority submit 

such allocations or the results of such auction (except allocations to 

or auctions for such units of TR SO2 Group 1 allowances remaining 
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Page 660 of 1339

unallocated or not auctioned in a set-aside for any recipients after 

completion of such allocations or auctions) to the Administrator no 

later than June 1 of the fourth year before the year of such control 

period.

(iv) Requires, to the extent the State adopts provisions for 

allocations or auctions of TR SO2 Group 1 allowances for any TR SO2

Group 1 units covered by §§97.611(b) and 97.612(a), that the State or 

the permitting authority submit such allocations or the results of 

such auction (except allocations to or auctions for such units of TR 

SO2 Group 1 allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 

auctions) to the Administrator by July 1 of the year of such control 

period. 

(v) Does not provide for any change, after the submission deadlines in 

paragraphs (d)(2)(ii), (iii), and (iv) 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; 

(3) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (d)(1) or (2) of this section by 

December 1 of the year before the year of the deadline for submission 

of allocations or auction results under paragraphs (d)(2)(ii) and 

(iii) of this section applicable to the first control period for which 
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Page 661 of 1339

the State wants to make such allocations or hold such auction under 

paragraph (d)(1) or (2) of this section.

(f) Notwithstanding the provisions of paragraph (a) of this section, a 

State listed in paragraph (b) may adopt and include in a SIP revision, 

and the Administrator will approve, as correcting the deficiency in 

the SIP that is the basis for the TR Federal Implementation Plan set 

forth in paragraphs (a) and (d) of this section, regulations that are 

substantively identical to the TR SO2 Group 1 Trading Program set forth 

in §§97.602 through 97.635, except that the SIP revision may:

(1) Adopt, as TR SO2 Group 1 allowance allocation provisions replacing 

the provisions in §§97.611(a) and (b) and 97.612(a) with regard to the 

control period in 2014 and thereafter, provisions substantively 

identical to those provisions, except that the State or the permitting 

authority allocates in lieu of the Administrator; or 

(2) Adopt, as TR SO2 Group 1 allowance allocation provisions replacing 

the provisions in §§97.611(a) and (b) and 97.612(a) with regard to the 

control period in 2014 and thereafter, any methodology under which the 

State or the permitting authority allocates in lieu of the 

Administrator 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 the 

control period not exceeding the amount of the State’s SO2 Group 1 
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Page 662 of 1339

trading budget minus the amounts of the State’s Indian country new 

unit set-aside and of TR SO2 Group 1 allowances already allocated and 

recorded by the Administrator, for such control period.

(ii) Requires, to the extent the State adopts provisions for 

allocations or auction of TR SO2 Group 1 allowances for any TR SO2

Group 1 units covered by §97.611(a) for any control period starting in 

2014, that the State or the permitting authority submit such 

allocations or the results of such auction for such control period 

(except allocations to or auctions for such units of TR SO2 Group 1 

allowances remaining unallocated or not auctioned in a set-aside for 

recipients other than such units after completion of such allocations 

or auctions) 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 

June 1 of the 

fourth year 
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Page 663 of 1339

thereafter before the 

year of the 

control period

(iii) Requires, to the extent the State adopts provisions for 

allocations or auction of TR SO2 Group 1 allowances for any TR SO2

Group 1 units covered by §97.611(a) for any control period in 2020 and 

any year thereafter, that the State or the permitting authority submit 

such allocations or the results of such auction (except allocations to 

or auctions for such units of TR SO2 Group 1 allowances remaining 

unallocated or not auctioned in a set-aside for any recipients after 

completion of such allocations or auctions) to the Administrator no 

later than June 1 of the fourth year before the year of such control 

period.

(iv) Requires, to the extent the State adopts provisions for 

allocations or auctions of TR SO2 Group 1 allowances for any TR SO2

Group 1 units covered by §§97.611(b) and 97.612(a), that the State or 

the permitting authority submit such allocations or the results of 

such auction (except allocations to or auctions for such units of TR 

SO2 Group 1 allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 

auctions) to the Administrator by July 1 of the year of such control 

period.

(v) Does not provide for any change, after the submission deadlines in 

paragraphs (d)(1)(ii)(B) and (C) of this section, in the allocations 
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Page 664 of 1339

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;

(3) Provided that the State may also adopt, in addition to the 

definitions in §97.602, 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 (e)(2) of this section; and

(4) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (e)(1) or paragraphs (e)(2) and 

(3) of this section by December 1 of the year before the year of the 

deadline for submission of allocations or auction results under 

paragraphs (e)(2)(ii) and (iii) of this section applicable to the 

first control period for which the State wants to make such 

allocations or hold such auction under paragraph (e)(1) or (2) of this 

section. 

(g) Notwithstanding the provisions of paragraph (a) of this section, a 

State listed in paragraph (c) 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) 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 of the State’s TR SO2 Group 2 trading 

budget minus the sum of the amounts of the State’s new unit set-aside 

and Indian country new unit set-aside for 2013 under §97.710(a); 

(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) may adopt and include in a SIP revision, 

and the Administrator will approve, regulations revising the TR SO2

Group 2 Trading Program as follows and not making any other 

substantive revisions of the TR SO2 Group 2 Trading Program:

(1) The State may adopt, as TR SO2 Group 2 allowance allocation 

provisions replacing the provisions in §§97.711(a) and (b) and 

97.712(a) with regard to the control period in 2014 and thereafter, 

provisions substantively identical to those provisions, except that 

the State or the permitting authority allocates in lieu of the 

Administrator; or 

(2) The State may adopt, as TR SO2 Group 2 allowance allocation 

provisions replacing the provisions in §§97.711(a) and (b) and 

97.712(a) with regard to the control period in 2014 and thereafter, 

any methodology under which the State or the permitting authority 

allocates in lieu of the Administrator or auctions TR SO2 Group 2 

allowances and may adopt, in addition to the definitions in §97.702, 

one or more definitions that shall apply only to terms as used in the 

adopted TR SO2 Group 2 allowance allocation or auction, if such 

methodology—
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(i) Requires the State or the permitting authority to allocate and, if 

applicable, auction a total amount of TR SO2 Group 2 allowances for the 

control period not exceeding the amount of the State’s TR SO2 Group 2 

trading budget minus the amounts of the State’s Indian country new 

unit set-aside and of TR SO2 Group 2 allowances already allocated and 

recorded by the Administrator, for such control period.

(ii) Requires, to the extent the State adopts provisions for 

allocations or auction of TR SO2 Group 2 allowances for any TR SO2

Group 2 units covered by §97.711(a) for any control period starting in 

2014, that the State or the permitting authority submit such 

allocations or the results of such auction for such control period 

(except allocations to or auctions for such units of TR SO2 Group 2 

allowances remaining unallocated or not auctioned in a set-aside for 

recipients other than such units after completion of such allocations 

or auctions) 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
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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 auction of TR SO2 Group 2 allowances for any TR SO2

Group 2 units covered by §97.711(a) for any control period in 2020 and 

any year thereafter, that the State or the permitting authority submit 

such allocations or the results of such auction (except allocations to 

or auctions for such units of TR SO2 Group 2 allowances remaining 

unallocated or not auctioned in a set-aside for any recipients after 

completion of such allocations or auctions) to the Administrator no 

later than June 1 of the fourth year before the year of such control 

period.

(iv) Requires, to the extent the State adopts provisions for 

allocations or auctions of TR SO2 Group 2 allowances for any TR SO2

Group 2 units covered by §§97.711(b) and 97.712(a), that the State or 

the permitting authority submit such allocations or the results of 

such auction (except allocations to or auctions for such units of TR 

SO2 Group 2 allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 
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auctions) to the Administrator by July 1 of the year of such control 

period.

(v) Does not provide for any change, after the submission deadlines in 

paragraphs (d)(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 DDDDD of part 97 of this chapter;

(3) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (f)(1) or (2) of this section by 

December 1 of the year before the year of the deadline for submission 

of allocations or auction results under paragraphs (f)(2)(ii) and 

(iii) of this section applicable to the first control period for which 

the State wants to make such allocations or hold such auction under 

paragraph (f)(1) or (2) of this section. 

(i) Notwithstanding the provisions of paragraph (a) of this section, a 

State listed in paragraph (c) may adopt and include in a SIP revision, 

and the Administrator will approve, as correcting the deficiency in 

the SIP that is the basis for the TR Federal Implementation Plan set 

forth in paragraphs (a) and (f) of this section, regulations that are 

substantively identical to the TR SO2 Group 2 Trading Program set forth 

in §§97.702 through 97.735, except that the SIP revision may:
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(1) Adopt, as TR SO2 Group 2 allowance allocation provisions replacing 

the provisions in §§97.711(a) and (b) and 97.712(a) with regard to the 

control period in 2014 and thereafter, provisions substantively 

identical to those provisions, except that the State or the permitting 

authority allocates in lieu of the Administrator; or 

(2) Adopt, as TR SO2 Group 2 allowance allocation provisions replacing 

the provisions in §§97.711(a) and (b) and 97.712(a) with regard to the 

control period in 2014 and thereafter, any methodology under which the 

State or the permitting authority allocates in lieu of the 

Administrator 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 the 

control period not exceeding the amount of the State’s SO2 Group 2 

trading budget minus the amounts of the State’s Indian country new 

unit set-aside and of TR SO2 Group 2 allowances already allocated and 

recorded by the Administrator, for such control period.

(ii) Requires, to the extent the State adopts provisions for 

allocations or auction of TR SO2 Group 2 allowances for any TR SO2

Group 2 units covered by §97.711(a) for any control period starting in 

2014, that the State or the permitting authority submit such 

allocations or the results of such auction for such control period 

(except allocations to or auctions for such units of TR SO2 Group 2 

allowances remaining unallocated or not auctioned in a set-aside for 
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recipients other than such units after completion of such allocations 

or auctions) 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 auction of TR SO2 Group 2 allowances for any TR SO2

Group 2 units covered by §97.711(a) for any control period in 2020 and 

any year thereafter, that the State or the permitting authority submit 

such allocations or the results of such auction (except allocations to 

or auctions for such units of TR SO2 Group 2 allowances remaining 

unallocated or not auctioned in a set-aside for any recipients after 

completion of such allocations or auctions)to the Administrator no 
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later than June 1 of the fourth year before the year of such control 

period.

(iv) Requires, to the extent the State adopts provisions for 

allocations or auctions of TR SO2 Group 2 allowances for any TR SO2

Group 2 units covered by §§97.711(b) and 97.712(a), that the State or 

the permitting authority submit such allocations or the results of 

such auction (except allocations to or auctions for such units of TR 

SO2 Group 2 allowances remaining unallocated or not auctioned in a setaside for any recipients after completion of such allocations or 

auctions) to the Administrator by July 1 of the year of such control 

period. 

(v) Does not provide for any change, after the submission deadlines in 

paragraphs (d)(1)(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 DDDDD of part 97 of this chapter;

(3) Provided that the State may also adopt, in addition to the 

definitions in §97.702, 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 (g)(2) of this section; and

(4) Provided that the State must submit a complete SIP revision 

meeting the requirements of paragraph (g)(1) or paragraphs (g)(2) and 
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(3) of this section by December 1 of the year before the year of the 

deadline for submission of allocations or auction results under 

paragraphs (g)(2)(ii) and (iii) of this section applicable to the 

first control period for which the State wants to make such 

allocations or hold such auction under paragraph (g)(1) or (2) of this 

section. 

(j) Following promulgation of an approval by the Administrator of a 

State's SIP revision as correcting 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.

(k) Notwithstanding the provisions of paragraph (h) of this section, 

if, at the time of such approval of the State's SIP revision, the 

Administrator has already allocated any TR SO2 Group 1 allowances or 

any TR SO2 Group 2 allowances (as applicable) to sources in the State 

for any years, the provisions of part 97 of this chapter authorizing 

the Administrator to complete the allocation of TR SO2 Group 1 

allowances or TR SO2 Group 2 allowances (as applicable) for those years 

shall continue to apply, unless provided otherwise by such approval of 

the State’s SIP revision.

Subpart B—Alabama 
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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 §52.37(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 allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP 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 
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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 §52.37(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 allocated any TR NOX Ozone Season allowances 

to unit in the State for any years, the provisions of subpart BBBBB of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Ozone Season allowances for those years shall 

continue to apply, unless provided otherwise by such approval of the 

State’s SIP revision. 

11. Section 52.55 is added to read as follows:

§ 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 
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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, 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 allocated 

any TR SO2 Group 2 allowances to unit in the State for any years, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 

Administrator to complete the allocation of TR SO2 Group 2 allowances 

for those years 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:

§ 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 
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the basis for the TR Federal Implementation Plan under §52.37(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 allocated 

any TR NOX Ozone Season allowances to unit in the State for any years, 

the provisions of subpart BBBBB of part 97 of this chapter authorizing 

the Administrator to complete the allocation of TR NOX Ozone Season 

allowances for those years shall continue to apply, unless provided 

otherwise by such approval of the State’s SIP revision. 

Subpart I—Delaware 

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: 
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(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) After recording in the appropriate compliance accounts the 

deductions required for the control period in 2011 for 

compliance with the CAIR NOX emissions limitation and for any 

related excess emissions, the Administrator will remove the CAIR 

NOX allowances in the CAIR NOX Allowance Tracking System 

accounts, and, thereafter, no surrender or deduction of such 

allowances for excess emissions in any control period will be 

required; and 

(4) After recording in the appropriate compliance accounts the 

deductions required for the control period in 2011 for 

compliance with the CAIR NOX Ozone Season emissions limitation 
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and for any related excess emissions, the Administrator will 

remove the CAIR NOX Ozone Season allowances in the CAIR NOX Ozone 

Season Allowance Tracking System accounts, and, thereafter, no 

surrender or deduction of such allowances for excess emissions 

in any control period will be required.

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,

(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
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(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

(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) After recording in the appropriate compliance accounts the 

deductions required for the control period in 2011 for 

compliance with the CAIR NOX emissions limitation and for any 

related excess emissions, the Administrator will remove the CAIR 

NOX allowances in the CAIR NOX Allowance Tracking System 

accounts, and, thereafter, no surrender or deduction of such 

allowances for excess emissions in any control period will be 

required; and 

(4) After recording in the appropriate compliance accounts the 

deductions required for the control period in 2011 for 

compliance with the CAIR NOX Ozone Season emissions limitation 

and for any related excess emissions, the Administrator will 

remove the CAIR NOX Ozone Season allowances in the CAIR NOX Ozone 

Season Allowance Tracking System accounts, and, thereafter, no 

surrender or deduction of such allowances for excess emissions 

in any control period will be required.

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?

(a) The owner and operator of each source and each unit located in the 

State of Florida and for which requirements are set forth under the TR 
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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 Florida’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Florida’s SIP revision described in 

paragraph (a) of this section, the Administrator has already allocated 

any TR NOX Ozone Season allowances to unit in the State for any years, 

the provisions of subpart BBBBB of part 97 of this chapter authorizing 

the Administrator to complete the allocation of TR NOX Ozone Season 

allowances for those years shall continue to apply, unless provided 

otherwise by such approval of the State’s SIP revision. 

Subpart L--Georgia

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 
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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 §52.37(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 allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

(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 §52.37(b), 
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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 allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

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 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 §52.38, 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 Georgia’s SIP revision described in 

paragraph (a) of this section, the Administrator has already allocated 

any TR SO2 Group 2 allowances to unit in the State for any years, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 

Administrator to complete the allocation of TR SO2 Group 2 allowances 

for those years 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?

(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 §52.37(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 Illinois’ SIP revision 

described in paragraph (a)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP 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 correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 
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Page 688 of 1339

of TR NOX Ozone Season allowances for those years 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 under §52.38, 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 allocated 

any TR SO2 Group 1 allowances to unit in the State for any years, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation of TR SO2 Group 1 allowances 

for those years shall continue to apply, unless provided otherwise by 

such approval of the State’s SIP revision. 
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Subpart P—Indiana 

22. Section 52.789 is amended by adding paragraphs (c), (d), and 

(e) to read as follows:

§ 52.789 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of nitrogen oxides?

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of 

this section and subparts AA through II and AAAA through IIII of 

part 97 of this chapter to the contrary: 

(1) With regard to any control period that begins after December 

31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section 

relating to NOX annual or ozone season emissions shall not be 

applicable; and

(ii) The Administrator will not carry out any of the functions 

set forth for the Administrator in subparts AA through II and 

AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any 

CAIR NOX allowances or CAIR NOX Ozone Season allowances allocated 

for 2012 or any year thereafter;
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(3) By October 31, 2011, the Administrator will remove from CAIR

NOX Allowance Tracking System accounts all CAIR NOX allowances 

allocated for a control period in 2012 and any subsequent year, 

and, thereafter, no surrender or deduction of such allowances 

for excess emissions in any control period will be required; and 

(4) By October 31, , 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 surrender or 

deduction of such allowances for excess emissions in any control 

period will be required.

(d)(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 correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Indiana’s SIP revision 
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described in paragraph (d)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

(e)(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 §52.37(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 Indiana’s SIP revision 

described in paragraph (e)(1) of this section, the Administrator has 

already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 
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apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

23. Section 52.790 is amended by designating the introductory 

text as paragraph (a) and adding new paragraphs (b) and (c) to 

read as follows:

§ 52.790 Interstate pollutant transport provisions; What are the FIP 

requirements for decreases in emissions of sulfur dioxide?

* * * * * 

(b) Notwithstanding any provisions of paragraph (a) of this 

section and subparts AAA through III of part 97 of this chapter 

and any State’s SIP to the contrary: 

(1) With regard to any control period that begins after December 

31, 2011,

(i) The provisions of paragraph (a) of this section relating to 

SO2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions 

set forth for the Administrator in subparts AAA through III of 

part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any 

CAIR SO2 allowances allocated for 2012 or any year thereafter.
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(c)(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 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 §52.38, 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 Indiana’s SIP revision 

described in paragraph (c)(1) of this section, the Administrator has 

already allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 1 allowances for those years 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 for which requirements are set forth under the 
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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 Iowa’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Iowa’s SIP revision 

described in paragraph (a)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP 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 for which requirements are set forth under the TR SO2

Group 1 Trading Program in subpart CCCCC of part 97 of this chapter 
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Page 695 of 1339

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 Iowa’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 Iowa’s SIP revision described in 

paragraph (a) of this section, the Administrator has already allocated 

any TR SO2 Group 1 allowances to unit in the State for any years, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation of TR SO2 Group 1 allowances 

for those years 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?

(a)(1) The owner and operator of each source and each unit located in 

the State of Kansas 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 
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Page 696 of 1339

approval by the Administrator of a revision to Kansas’ State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Kansas’ SIP revision 

described in paragraph (a)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

(b)[Reserved] 

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 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 Kansas’ State 
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Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 Kansas’ SIP revision described in 

paragraph (a) of this section, the Administrator has already allocated 

any TR SO2 Group 2 allowances to unit in the State for any years, the 

provisions of subpart DDDDD of part 97 of this chapter authorizing the 

Administrator to complete the allocation of TR SO2 Group 2 allowances 

for those years 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 §52.37(a), 
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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 allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP 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 §52.37(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 
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Page 699 of 1339

already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

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 §52.38, 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 

allocated any TR SO2 Group 1 allowances to unit in the State for any 

years, the provisions of subpart CCCCC of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR SO2
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Group 1 allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

Subpart T—Louisiana 

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; 
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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 October 31, 2011, 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 surrender or deduction of 

such allowances for excess emissions in any control period will 

be required; and 

(4) By October 31, , 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 surrender or 

deduction of such allowances for excess emissions in any control 

period will be required.

(d)(1) The owner and operator of each source and each unit located in 

the State of Louisiana 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 Louisiana’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(b), 
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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 Louisiana’s SIP revision 

described in paragraph (d)(1) of this section, the Administrator has 

already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

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 §52.37(a), 
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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 Maryland’s SIP revision 

described in paragraph (a)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP 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 §52.37(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 
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already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

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 §52.38, 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 

allocated any TR SO2 Group 1 allowances to unit in the State for any 

years, the provisions of subpart CCCCC of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR SO2
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Group 1 allowances for those years 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 October 31, , 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 surrender or deduction of such allowances 

for excess emissions in any control period will be required; and 

(4) By October 31, 2011, 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 surrender or 

deduction of such allowances for excess emissions in any control 

period will be required.

(d)(1) The owner and operator of each source and each unit located in 

the State of Michigan 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 Michigan’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Michigan’s SIP revision 

described in paragraph (a)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

(e) [Reserved]

34. Section 52.1187 is amended by designating the introductory 

text as paragraph (a) and adding a 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?

* * * * * 

(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.

(c)(1)_ The owner and operator of each source and each unit located in 

the State of Michigan 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 Michigan’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 Maryland’s SIP revision 

described in paragraph (c)(1) of this section, the Administrator has 

already allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 
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Page 709 of 1339

SO2 Group 1 allowances for those years 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 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 Minnesota’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(a), 

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 Minnesota’s SIP revision 

described in paragraph (c)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 
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authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

36. Section 52.1241 is amended by adding paragraph (c) to read as 

follows:

§ 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 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 Minnesota’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 Minnesota’s SIP revision 

described in paragraph (c)(1) of this section, the Administrator has 

already allocated any TR SO2 Group 2 allowances to unit in the State 

for any years, the provisions of subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 
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SO2 Group 2 allowances for those years shall 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 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 Mississippi’s 

State Implementation Plan (SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal Implementation Plan under 

§52.37(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 Mississippi’s SIP revision 

described in paragraph (a) of this section, the Administrator has 

already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 
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Page 712 of 1339

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 §52.37(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 Missouri’s SIP revision 

described in paragraph (a)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX
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Annual allowances for those years 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 §52.38, 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 Missouri’s SIP revision described 

in paragraph (a) of this section, the Administrator has already 

allocated any TR SO2 Group 1 allowances to unit in the State for any 

years, the provisions of subpart CCCCC of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR SO2

Group 1 allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 
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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 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 Nebraska’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(a), 

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 Nebraska’s SIP revision described 

in paragraph (a) of this section, the Administrator has already 

allocated any TR NOX Annual allowances to unit in the State for any 

years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

41. Section 52.1429 is added to read as follows:
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§ 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 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 Nebraska’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 Nebraska’s SIP revision described 

in paragraph (a) of this section, the Administrator has already 

allocated any TR SO2 Group 2 allowances to unit in the State for any 

years, the provisions of subpart DDDDD of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR SO2

Group 2 allowances for those years 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 October 31, 2011, 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 surrender or deduction of 
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Page 717 of 1339

such allowances for excess emissions in any control period will 

be required; and 

(4) By October 31, 2011, 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 surrender or 

deduction of such allowances for excess emissions in any control 

period will be required.

(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 §52.37(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 allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX
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Annual allowances for those years 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 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 

§52.37(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 allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

revision. 
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43. Section 52.1585 is amended by designating the introductory 

text as paragraph (a) and adding new paragraphs (b) and (c) to 

read as follows:

§ 52.1585 Interstate pollutant transport provisions; What are the 

FIP requirements for decreases in emissions of sulfur dioxide?

* * * * * 

(b) Notwithstanding any provisions of paragraph (a) of this 

section and subparts AAA through III of part 97 of this chapter 

and any State’s SIP to the contrary: 

(1) With regard to any control period that begins after December 

31, 2011,

(i) The provisions of paragraph (a) of this section relating to 

SO2 emissions shall not be applicable; and

(ii) The Administrator will not carry out any of the functions 

set forth for the Administrator in subparts AAA through III of 

part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any 

CAIR SO2 allowances allocated for 2012 or any year thereafter.

(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 
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Page 720 of 1339

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, 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 allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 1 allowances for those years 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 amended 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 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 York’s State 
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Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 New York’s SIP revision 

described in paragraph (a)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

(b)(1) The owner and operator of each source and each unit located in 

the State of New York 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 York’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(b), 

except to the extent the Administrator’s approval is partial or 

conditional.
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(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 allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

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 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 York’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 New York’s SIP revision described 

in paragraph (a) of this section, the Administrator has already 
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allocated any TR SO2 Group 1 allowances to unit in the State for any 

years, the provisions of subpart CCCCC of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR SO2

Group 1 allowances for those years 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 amended to read as follows:

§ 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 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 North Carolina’s 

State Implementation Plan (SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal Implementation Plan under 

§52.37(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 North Carolina’s SIP

revision described in paragraph (a)(1) of this section, the 

Administrator has already allocated any TR NOX Annual allowances to 
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Page 724 of 1339

unit in the State for any years, the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Annual allowances for those years shall continue 

to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

(b)(1) The owner and operator of each source and each unit located in 

the State of North Carolina 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 

North Carolina’s State Implementation Plan (SIP) as correcting the 

SIP’s deficiency that is the basis for the TR Federal Implementation 

Plan under §52.37(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 North Carolina’s SIP

revision described in paragraph (b)(1) of this section, the 

Administrator has already allocated any TR NOX Ozone Season allowances 

to unit in the State for any years, the provisions of subpart BBBBB of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Ozone Season allowances for those years shall 

continue to apply, unless provided otherwise by such approval of the 

State’s SIP revision. 
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47. Section 52.1785 is amended 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 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 North Carolina’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 North Carolina’s SIP revision 

described in paragraph (a) of this section, the Administrator has 

already allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 1 allowances for those years 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:
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§ 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 §52.37(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 allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP 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 
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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 §52.37(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 allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

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 
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Page 728 of 1339

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, 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 allocated 

any TR SO2 Group 1 allowances to unit in the State for any years, the 

provisions of subpart CCCCC of part 97 of this chapter authorizing the 

Administrator to complete the allocation of TR SO2 Group 1 allowances 

for those years shall continue to apply, unless provided otherwise by 

such approval of the State’s SIP revision. 

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 
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that is the basis for the TR Federal Implementation Plan under 

§52.37(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 allocated any TR NOX Annual allowances to 

unit in the State for any years, the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Annual allowances for those years shall continue 

to apply, unless provided otherwise by such approval of the State’s 

SIP 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 §52.37(b), except to the extent the Administrator’s approval is 

partial or conditional.
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(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 allocated any TR NOX Ozone Season allowances 

to unit in the State for any years, the provisions of subpart BBBBB of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Ozone Season allowances for those years shall 

continue to apply, unless provided otherwise by such approval of the 

State’s SIP 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?

(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 §52.38, 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 
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already allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 1 allowances for those years 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 amended to read as follows:

§ 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 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 South Carolina’s 

State Implementation Plan (SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal Implementation Plan under 

§52.37(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 South Carolina’s SIP

revision described in paragraph (a)(1) of this section, the 

Administrator has already allocated any TR NOX Annual allowances to 
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unit in the State for any years, the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Annual allowances for those years shall continue 

to apply, unless provided otherwise by such approval of the State’s 

SIP revision. 

(b)(1) The owner and operator of each source and each unit located in 

the State of South Carolina 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 

South Carolina’s State Implementation Plan (SIP) as correcting the 

SIP’s deficiency that is the basis for the TR Federal Implementation 

Plan under §52.37(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 South Carolina’s SIP

revision described in paragraph (b)(1) of this section, the 

Administrator has already allocated any TR NOX Ozone Season allowances 

to unit in the State for any years, the provisions of subpart BBBBB of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Ozone Season allowances for those years shall 

continue to apply, unless provided otherwise by such approval of the 

State’s SIP revision. 
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53. Section 52.2141 is amended 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 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 South Carolina’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 South Carolina’s SIP revision 

described in paragraph (a) of this section, the Administrator has 

already allocated any TR SO2 Group 2 allowances to unit in the State 

for any years, the provisions of subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 2 allowances for those years 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:
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§ 52.2240 Interstate pollutant transport provisions; What are the 

FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of 

this section and subparts AA through II and AAAA through IIII of 

part 97 of this chapter to the contrary: 

(1) With regard to any control period that begins after December 

31, 2011,

(i) The provisions in paragraphs (a) and (b) of this section 

relating to NOX annual or ozone season emissions shall not be 

applicable; and

(ii) The Administrator will not carry out any of the functions 

set forth for the Administrator in subparts AA through II and 

AAAA through IIII of part 97 of this chapter; and

(2) The Administrator will not deduct for excess emissions any 

CAIR NOX allowances or CAIR NOX Ozone Season allowances allocated 

for 2012 or any year thereafter;

(3) By October 31, 2011, 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 surrender or deduction of 
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Page 735 of 1339

such allowances for excess emissions in any control period will 

be required; and 

(4) By October 31, 2011, 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 surrender or 

deduction of such allowances for excess emissions in any control 

period will be required.

(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 Implementation Plan under §52.37(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 Tennessee’s SIP revision 

described in paragraph (d)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX
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Annual allowances for those years 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 §52.37(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 Tennessee’s SIP revision 

described in paragraph (e)(1) of this section, the Administrator has 

already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

revision. 
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55. Section 52.2241 is amended by designating the introductory 

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?

* * * * * 

(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 
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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, 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 Tennessee’s SIP revision 

described in paragraph (c)(1) of this section, the Administrator has 

already allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 1 allowances for those years 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 adding new paragraphs (c),(d), 

and (e) to read as follows:

§ 52.2283 Interstate pollutant transport provisions; What are the 

FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *

(c) Notwithstanding any provisions of paragraphs (a) and (b) of 

this section and subparts AA through II of part 97 of this 

chapter to the contrary: 
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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 October 31, 2011, 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 surrender or deduction of 

such allowances for excess emissions in any control period will 

be required; and 

(4) By October 31, 2011, 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 surrender or 

deduction of such allowances for excess emissions in any control 

period will be required.
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(d)(1) The owner and operator of each source and each unit located in 

the State of Texas 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 Texas’ State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Texas’ SIP revision

described in paragraph (d)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

(e)(1) The owner and operator of each source and each unit located in 

the State of Texas 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 Texas’ State 
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Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Texas’ SIP revision 

described in paragraph (e)(1) of this section, the Administrator has 

already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

57. Section 52.2284 is amended by designating the introductory 

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?

* * * * * 

(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: 
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(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 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 Texas’ State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.38, 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 Texas’ SIP revision 

described in paragraph (c)(1) of this section, the Administrator has 

already allocated any TR SO2 Group 2 allowances to unit in the State 

for any years, the provisions of subpart DDDDD of part 97 of this 
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chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 2 allowances for those years 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 correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX
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Annual allowances for those years 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 §52.37(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 paragraph (b)(1) of this section, the Administrator has 

already allocated any TR NOX Ozone Season allowances to unit in the 

State for any years, the provisions of subpart BBBBB of part 97 of 

this chapter authorizing the Administrator to complete the allocation 

of TR NOX Ozone Season allowances for those years shall continue to 

apply, unless provided otherwise by such approval of the State’s SIP 

revision. 

59. Section 52.2241 is added to read as follows:
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§ 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 §52.38, 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 

allocated any TR SO2 Group 1 allowances to unit in the State for any 

years, the provisions of subpart CCCCC of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR SO2

Group 1 allowances for those years 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?
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(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 

§52.37(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 paragraph (a)(1) of this section, the 

Administrator has already allocated any TR NOX Annual allowances to 

unit in the State for any years, the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Annual allowances for those years shall continue 

to apply, unless provided otherwise by such approval of the State’s 

SIP 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 
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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 §52.37(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 allocated any TR NOX Ozone Season allowances 

to unit in the State for any years, the provisions of subpart BBBBB of 

part 97 of this chapter authorizing the Administrator to complete the 

allocation of TR NOX Ozone Season allowances for those years shall 

continue to apply, unless provided otherwise by such approval of the 

State’s SIP 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 
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the basis for the TR Federal Implementation Plan under §52.38, 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 allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 1 allowances for those years shall 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,
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(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 October 31, 2011, the Administrator will remove from the 

CAIR NOX Allowance Tracking System accounts all CAIR NOX Ozone 

Season allowances allocated for a control period in 2012 and any 

subsequent year, and, thereafter, no surrender or deduction of 

such allowances for excess emissions in any control period will 

be required; and 

(4) By October 31, 2011, 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 surrender or 

deduction of such allowances for excess emissions in any control 

period will be required.
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(d)(1) The owner and operator of each source and each unit located in 

the State of Wisconsin 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 Wisconsin’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 

the basis for the TR Federal Implementation Plan under §52.37(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 Wisconsin’s SIP revision 

described in paragraph (d)(1) of this section, the Administrator has 

already allocated any TR NOX Annual allowances to unit in the State for 

any years, the provisions of subpart AAAAA of part 97 of this chapter 

authorizing the Administrator to complete the allocation of TR NOX

Annual allowances for those years shall continue to apply, unless 

provided otherwise by such approval of the State’s SIP revision. 

(e) [Reserved] 

63. Section 52.2588 is amended by designating the introductory 

text as paragraph (a) and adding a new paragraphs (b) and (c) to 

read as follows:
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§ 52.2588 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 Wisconsin 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 Wisconsin’s State 

Implementation Plan (SIP) as correcting the SIP’s deficiency that is 
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the basis for the TR Federal Implementation Plan under §52.38, 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 Wisconsin’s SIP revision 

described in paragraph (c)(1) of this section, the Administrator has 

already allocated any TR SO2 Group 1 allowances to unit in the State 

for any years, the provisions of subpart CCCCC of part 97 of this 

chapter authorizing the Administrator to complete the allocation of TR 

SO2 Group 1 allowances for those years 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]

66. The authority citation for Part 78 continues to read as 

follows:
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Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et

seq.

§ 78.1 [Amended]

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 
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allowances based on the information as adjusted under §97.428 of 

this chapter. 

(vi) The finalization of control period emissions data, 

including retroactive adjustment based on audit.

(vii) The approval or disapproval of a petition under §97.435 

of this chapter. 

(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. 
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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 §97.535 

of this chapter. 

(15) Under subpart CCCCC of part 97 of this chapter,

(i) The decision on allocation of TR SO2 Group 1 allowances 

under §97.611(a)(2) and (b) of this chapter.

(ii) The decision on the transfer of TR SO2 Group 1 allowances 

under §97.623 of this chapter.

(iii) The decision on the deduction of TR SO2 Group 1 allowances 

under §§97.624 and 97.625 of this chapter. 

(iv) The correction of an error in an Allowance Management 

System account under §97.627 of this chapter. 

(iv) The adjustment of information in a submission and the 

decision on the deduction and transfer of TR SO2 Group 1 

allowances based on the information as adjusted under §97.628 of 

this chapter. 

(vi) The finalization of control period emissions data, 

including retroactive adjustment based on audit.
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(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.

(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. 

* * * * * 
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§ 78.2 [Amended]

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:

(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 
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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 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 
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part for the filing of a responsive document or for otherwise 

responding.

§ 78.3 [Amended]

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) * * * 

(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: 
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(i) The designated representative for a unit or source, or the 

authorized account representative for any Allowance Management 

System account, covered by the decision; or

(ii) Any interested person with regard to the decision.

* * * * *

(d) * * *

(11) Any provision or requirement of subparts AAAAA, BBBBB, 

CCCCC, or DDDDD of part 97 of this chapter, including the 

standard requirements under §97.406, §97.506, §97.606, or 

§97.706 of this chapter and any emission monitoring or reporting 

requirements.

§ 78.4 [Amended]

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”; and

iii. Redesignating the paragraph as paragraph (a)(1)(iii); and
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b. Adding paragraphs (a)(1) introductory text, (a)(1)(i), 

(a)(1)(ii) and (a)(2) to read as follows: 

§ 78.4 Filings.

(a)(1) All original filings made under this part shall be signed 

by the person making the filing or by an attorney or authorized 

representative, in accordance with the following requirements:

(i) Any filings on behalf of owners and operators of a affected 

unit or affected source, TR NOX Annual unit or TR NOX Annual 

source, TR NOX Ozone Season unit or TR NOX Ozone Season source, 

TR SO2 Group 1 unit or TR SO2 Group 1 source, TR SO2 Group 2 unit 

or TR SO2 Group 2 source, or a unit for which a TR opt-in 

application is submitted and not withdrawn shall be signed by 

the designated representative. Any filing on behalf of persons 

with an ownership interest with respect to allowances, TR NOX

Annual allowances, TR NOX Ozone Season allowances, TR SO2 Group 1 

allowances, or TR SO2 Group 2 allowances in a general account 

shall be signed by the authorized account representative. 

(ii) Any filings on behalf of owners and operators of a NOX

Budget unit or NOX Budget source shall be signed by the NOX

authorized account representative. Any filing on behalf of 

persons with an ownership interest with respect to NOX allowances 
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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 their 

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]
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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 for new units.

97.413 Authorization of designated representative and alternate 

designated representative.

97.414 Responsibilities of designated representative and 

alternate designated representative.

97.415 Changing designated representative and alternate 

designated representative; changes in owners and operators.

97.416 Certificate of representation.

97.417 Objections concerning designated representative and 

alternate designated representative.

97.418 Delegation by designated representative and alternate 

designated representative.

97.419 [Reserved]

97.420 Establishment of compliance accounts and general 

accounts.
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97.421 Recordation of TR NOX Annual allowance allocations.

97.422 Submission of TR NOX Annual allowance transfers.

97.423 Recordation of TR NOX Annual allowance transfers.

97.424 Compliance with TR NOX Annual emissions limitation.

97.425 Compliance with TR NOX Annual assurance provisions.

97.426 Banking.

97.427 Account error.

97.428 Administrator’s action on submissions.

97.429 [RESERVED]

97.430 General monitoring, recordkeeping, and reporting 

requirements.

97.431 Initial monitoring system certification and 

recertification procedures.

97.432 Monitoring system out-of-control periods.

97.433 Notifications concerning monitoring.

97.434 Recordkeeping and reporting.

97.435 Petitions for alternatives to monitoring, recordkeeping, 

or reporting requirements.
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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 §52.37of this chapter, as a means of mitigating 

interstate transport of fine particulates and nitrogen oxides.

§ 97.402 Definitions.

The terms used in this subpart shall have the meanings set forth 

in this section as follows:

Acid Rain Program means a 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) of the United States 

Environmental Protection Agency, the Administrator's duly 

authorized representative under this subpart.
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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 §52.37(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;

(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, with regard to 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 
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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.

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.
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Alternate designated representative means, with regard to 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, in which are held TR NOX

Annual allowances available for 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, with regard to a 

general account, the natural person who is authorized, in 

accordance with this subpart, to transfer and otherwise dispose 

of TR NOX Annual allowances held in the general account and, with 
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regard to a TR NOX Annual source’s compliance account, the 

designated representative of the source.

Automated data acquisition and handling system or DAHS means the 

component of the continuous emission monitoring system, or other 

emissions monitoring system approved for use under this subpart, 

designed to interpret and convert individual output signals from 

pollutant concentration monitors, flow monitors, diluent gas 

monitors, and other component parts of the monitoring system to 

produce a continuous record of the measured parameters in the 

measurement units required by this subpart. 

Biomass means—

(1) Any organic material grown for the purpose of being 

converted to energy;

(2) Any organic byproduct of agriculture that can be converted 

into energy; or

(3) Any material that can be converted into energy and is 

nonmerchantable for other purposes, that is segregated from 

other material that is nonmerchantable for other purposes, and 

that is;
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(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:

(1) For a corporation, a president, secretary, treasurer, or 

vice-president or the corporation in charge of a principal 

business function or any other person who performs similar 

policy- or decision-making functions for the corporation;
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(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—

(1) Operating as part of a cogeneration system; and

(2) Producing on an annual average basis during the later of 

2005 or the 12-month period starting on the date that the unit 
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first produces electricity and during each calendar year after

the later of 2005 or the calendar year in which the unit first 

produces electricity—

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less than 5 percent of total 

energy output; and

(B) Useful power that, when added to one-half of useful thermal 

energy produced, is not less 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 
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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:

(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.
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(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 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 
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unit's date for commencement of commercial operation shall be 

the date on which the unit becomes a TR NOX Annual unit under 

§97.404.

(i) For a unit with a date for commencement of commercial 

operation as defined in the introductory text of paragraph (2) 

of this definition and that subsequently undergoes a physical 

change) 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 a designated 

representative where the same natural person is authorized under 

§§ 97.413(a) and 97.415(a) as the designated representative for 
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a group of one or more TR NOX Annual sources and units located in 

a State.

Common designated representative’s assurance level means, with

regard to a specific common designated representative and a 

State and control period in a given year for which the State 

assurance level is exceeded as described in §97.406(c)(2)(iii), 

the common designated representative’s share of the State NOX

Annual trading budget with the one-year variability limit for 

the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative:

(1) With regard to a total amount of NOX emissions from all TR 

NOX Annual units in a State during a control period in a given 

year, the total tonnage of NOX emissions during such control 

period from a group of one or more TR NOX Annual units located in 

the State and having the common designated representative as of 

the allowance transfer deadline for such control period; 

(2) With regard to a State NOX Annual trading budget for a 

control period in a given year, 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 
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having the common designated representative as of the allowance 

transfer deadline 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 to the Administrator for 

recordation in the compliance accounts for such TR NOX Annual 

units in accordance with the TR NOX Annual allowance auction 

provisions in a SIP revision approved by the Administrator under

§52.37(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 one-year 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, a control period in a given year, 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 0.87 (if the unit is 

a boiler combusting any amount of coal or coal-derived fuel 

during such control period), 0.14 (if the unit is a simple 
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combustion turbine during such control period), 0.70 (if the 

unit is a combined cycle turbine during such control period), 

0.46 (if the unit is a boiler combusting only fuel oil or 

natural gas during such control period), or 0.71 (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.

Compliance account means an Allowance Management System account, 

established by the Administrator for a TR NOX Annual source under 

this subpart, in which any TR NOX Annual allowance allocations 

for the TR NOX Annual units at the source are recorded and in 

which are held any TR NOX Annual allowances available for use for 

a control period in 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, 
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stack gas volumetric flow rate, stack gas moisture content, and 

O2 or CO2 concentration (as applicable), in a manner consistent 

with part 75 of this chapter and §§97.430 through 97.435. The 

following systems are the principal types of continuous emission 

monitoring systems:

(1) A flow monitoring system, consisting of a stack flow rate 

monitor and an automated data acquisition and handling system 

and providing a permanent, continuous record of stack gas 

volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A NOX concentration monitoring system, consisting of a NOX

pollutant concentration monitor and an automated data 

acquisition and handling system and providing a permanent, 

continuous record of NOX emissions, in parts per million (ppm);

(3) A NOX emission rate (or 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);
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(4) A moisture monitoring system, as defined in §75.11(b)(2) of 

this chapter and providing a permanent, continuous record of the 

stack gas moisture content, in percent H2O;

(5) A CO2 monitoring system, consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor plus suitable 

mathematical equations from which the CO2 concentration is 

derived) and an automated data acquisition and handling system 

and providing a permanent, continuous record of CO2 emissions, in 

percent CO2; and

(6) An O2 monitoring system, consisting of an O2 concentration 

monitor and an automated data acquisition and handling system 

and providing a permanent, continuous record of O2, in percent 

O2.

Control period means the period starting January 1 of a calendar 

year, except as provided in §97.406(c)(3), and ending on 

December 31 of the same year, inclusive.

Designated representative means, with regard to 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 
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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.

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
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(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.

Fuel oil means “fuel oil” as defined in §72.2 of this chapter.

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 
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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, with regard to 

a specific fuel, the amount of heat input attributed to the fuel 

(in mmBtu) divided by the unit operating time (in hr) during 

which the unit combusts the fuel.

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, as defined in 18 U.S.C. 1151:

(1) All land within the limits of any Indian reservation under 

the jurisdiction of the United States Government, 

notwithstanding the issuance of any patent, and, including 

rights-of-way running through the reservation;

(2) All dependent Indian communities within the borders of the 

United States whether within the original or subsequently 

acquired territory thereof, and whether within or without the 

limits of a state; and 
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(3) All Indian allotments, the Indian titles to which have not 

been extinguished, including rights-of-way running through the 

same.

Life-of-the-unit, firm power contractual arrangement means a 

unit participation power sales agreement under which a utility 

or industrial customer reserves, or is entitled to receive, a 

specified amount or percentage of nameplate capacity and 

associated energy generated by any specified unit and pays its 

proportional amount of such unit's total costs, pursuant to a 

contract:

(1) For the life of the unit;

(2) For a cumulative term of no less than 30 years, including 

contracts that permit an election for early termination; or

(3) For a period no less than 25 years or 70 percent of the 

economic useful life of the unit determined as of the time the 

unit is built, with option rights to purchase or release some 

portion of the nameplate capacity and associated energy 

generated by the unit at the end of the period.

Maximum design heat input means, 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 
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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.

Natural gas means “natural gas” as defined in §72.2 of this 

chapter.
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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, with regard to 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.

Owner means, with regard to a TR NOX Annual source or a TR NOX

Annual unit at a source respectively, any of the following 

persons:

(1) Any holder of any portion of the legal or equitable title in 

a TR NOX Annual unit at the source or the TR NOX Annual unit;

(2) Any holder of a leasehold interest in a TR NOX Annual unit at 

the source or the TR NOX Annual unit, provided that, unless 

expressly provided for in a leasehold agreement, “owner” shall 

not include a passive lessor, or a person who has an equitable 

interest through such lessor, whose rental payments are not 
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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.

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

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) For a topping-cycle unit, the use of reject heat from 

electricity production in a useful thermal energy application or 

process; or

(2) For a bottoming-cycle unit, the use of reject heat from 

useful thermal energy application or process in electricity 

production.
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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-fuelfired 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 §52.37(a) of this chapter

and, when used to refer to a geographic area, includes Indian 

country located within the borders of such State.

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
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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 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 §52.37(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). 

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:
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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 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 §52.37(a) of this chapter

(including such a program that is revised in a SIP revision 

approved by the Administrator under §52.37(a)(3) or (4) of this 

chapter) or with a SIP revision approved by the Administrator 

under §52.37(a)(5) of this chapter, as a means of mitigating 

interstate transport of fine particulates and NOX.
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TR NOX Annual unit means a unit that is subject to the TR NOX

Annual Trading Program.

TR NOX Ozone Season Trading Program means a multi-state NOX air 

pollution control and emission reduction program in accordance 

with subpart BBBBB of this part and 52.37(b) of this chapter

(including such a program that is revised by a State in a SIP 

revision approved by the Administrator under §52.37(b)(3) or (4) 

of this chapter) or with a SIP revision approved by the 

Administrator under §52.37(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 52.38(b) of this 

chapter (including such a program that is revised by a State in 

a SIP revision approved by the Administrator under §52.38(d) or 

(e) of this chapter) or with a SIP revision approved by the 

Administrator under §52.38(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 52.38(c) of this 

chapter (including such a program that is revised by a State in 
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a SIP revision approved by the Administrator under §52.38(g) or 

(h) of this chapter) or with a SIP revision approved by the 

Administrator under §52.38(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, 

fossil-fuel-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 
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processing or treatment of fuel combusted at the unit and any 

on-site emission controls).

Useful thermal energy means thermal energy that is:

(1) Made available to an industrial or commercial process (not a 

power production process), excluding any heat contained in 

condensate return or makeup water;

(2) Used in a heating application (e.g., space heating or 

domestic hot water heating); or

(3) Used in a space cooling application (i.e., in an absorption 

chiller).

Utility power distribution system means the portion of an 

electricity grid owned or operated by a utility and dedicated to 

delivering electricity to customers.

§ 97.403 Measurements, abbreviations, and acronyms.

Measurements, abbreviations, and acronyms used in this subpart 

are defined as follows:

Btu—British thermal unit

CO2—carbon dioxide

H2O—water
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hr—hour

kW—kilowatt electrical

kWh—kilowatt hour

lb—pound

mmBtu—million Btu

MWe—megawatt electrical

MWh—megawatt hour

NOX—nitrogen oxides

O2—oxygen

ppm—parts per million

scfh—standard cubic feet per hour

SO2—sulfur dioxide

yr—year

§ 97.404 Applicability.

(a) Except as provided in paragraph (b) of this section:
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(1) The following units in a State (including Indian country 

located 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, 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

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 (including Indian country located 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), (b)(2)(i), or 

(b)(2)(ii) of this section shall not be a TR NOX Annual unit:

(1)(i) Any unit:
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(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; 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 a unit qualifies as a cogeneration unit throughout the 

later of 2005 or the 12-month period starting on the date the 

unit first produces electricity and meets the requirements of 

paragraphs (b)(1)(i) of this section for at least one calendar 

year, but subsequently no longer meets such qualification and 

requirements, the unit shall become a TR NOX Annual unit starting 

on the earlier of January 1 after the first calendar year during 

which the unit first no longer qualifies as a cogeneration unit 

or January 1 after the first calendar year during which the unit 

no longer meets the requirements of paragraph (b)(1)(i)(B) of 

this section.

(2)(i) Any unit:

(A) Qualifying as a solid waste incineration unit throughout the 

later of 2005 or the 12-month period starting on the date the 
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unit first produces electricity and continuing to qualify as a 

solid waste incineration unit; and

(B) With an average annual fuel consumption of fossil fuel for 

the first 3 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 a unit qualifies 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 meets the 

requirements of paragraph (b)(2)(i) of this section for at least 

3 consecutive calendar years, but subsequently no longer meets 

such qualification and requirements, the unit shall become a TR 

NOX Annual unit starting on the earlier of January 1 after the 

first calendar year during which the unit first no longer 

qualifies as a solid waste incineration unit or January 1 after 

the first 3 consecutive calendar years after 2005 for which the 

unit has an average annual fuel consumption of fossil fuel of 20 

percent or more.

(c) A certifying official of an owner or operator of any unit or 

other equipment may submit a petition (including any supporting 
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documents) to the Administrator at any time for a determination 

concerning the applicability, under paragraphs (a) and (b) of 

this section, of the TR NOX Annual Trading Program to the unit or 

other equipment.

(1) Petition content. The petition shall be in writing and 

include the identification of the unit or other equipment and 

the relevant facts about the unit or other equipment. The 

petition and any other documents provided to the Administrator 

in connection with the petition shall include the following 

certification statement, signed by the certifying official: “I 

am authorized to make this submission on behalf of the owners 

and operators of the unit or other equipment for which the 

submission is made. I certify under penalty of law that I have 

personally examined, and am familiar with, the statements and 

information submitted in this document and all its attachments. 

Based on my inquiry of those individuals with primary 

responsibility for obtaining the information, I certify that the 

statements and information are to the best of my knowledge and 

belief true, accurate, and complete. I am aware that there are 

significant penalties for submitting false statements and 

information or omitting required statements and information, 

including the possibility of fine or imprisonment.”
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(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 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.
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(b) Special provisions. (1) A unit exempt under paragraph (a) of 

this section shall not emit any NOX, starting on the date that 

the exemption takes effect.

(2) For a period of 5 years from the date the records are 

created, the owners and operators of a unit exempt under 

paragraph (a) of this section shall retain, at the source that 

includes the unit, records demonstrating that the unit is 

permanently retired. The 5-year period for keeping records may 

be extended for cause, at any time before the end of the period, 

in writing by the Administrator. The owners and operators bear 

the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the 

designated representative of a unit exempt under paragraph (a) 

of this section shall comply with the requirements of the TR NOX

Annual Trading Program concerning all periods for which the 

exemption is not in effect, even if such requirements arise, or 

must be complied with, after the exemption takes effect.

(4) A unit exempt under paragraph (a) of this section shall lose 

its exemption on the first date on which the unit resumes 

operation. Such unit shall be treated, for purposes of applying 

allocation, monitoring, reporting, and recordkeeping 

requirements under this subpart, as a unit that commences 
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commercial operation on the first date on which the unit resumes 

operation.

§ 97.406 Standard requirements.

(a) Designated representative requirements. The owners and 

operators shall comply with the requirement to have a designated 

representative, and may have an alternate designated 

representative, in accordance with §§97.413 through 97.418.

(b) Emissions monitoring, reporting, and recordkeeping 

requirements. (1) The owners and operators, and the designated 

representative, of each TR NOX Annual source and each TR NOX

Annual unit at the source shall comply with the monitoring, 

reporting, and recordkeeping requirements of §§97.430 through 

97.435.

(2) The emissions data determined in accordance with §§97.430 

through 97.435 shall be used to calculate allocations of TR NOX

Annual allowances under §§97.411(a)(2) and (b) and 97.412 and to 

determine compliance with the TR NOX Annual emissions limitation 

and assurance provisions under paragraph (c) of this section, 

provided that, for each monitoring location from which mass 

emissions are reported, the mass emissions amount used in 

calculating such allocations and determining such compliance 

shall be the mass emissions amount for the monitoring location
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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 with any other remedy imposed, for the same 
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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 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 (as of the allowance transfer 

deadline 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 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 for such 
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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) Two times the amount by which total NOX emissions from all TR 

NOX Annual units at TR NOX Annual sources in the 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 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 one-year 

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 during a control period exceed the 

State assurance level or if a common designated representative’s

share of total NOX emissions from the TR NOX Annual units at TR 
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NOX Annual sources in a 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 deducted allowances. A TR NOX Annual allowance 

shall not be deducted, for compliance with the requirements 

under paragraphs (c)(1)(i) and (2)(i) through (iii) of this 

section, for a control period in a calendar year before the year 

for which the TR NOX Annual allowance was allocated.

(5) Allowance Management System requirements. Each TR NOX Annual 

allowance shall be held in, deducted from, or transferred into, 

out of, or between Allowance Management System accounts in 

accordance with this subpart.

(6) Limited authorization. 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

(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. 
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(7) Property right. A TR NOX Annual allowance does not constitute 

a property right.

(d) Title V permit requirements. (1) No title V permit revision 

shall be required for any allocation, holding, deduction, or 

transfer of TR NOX Annual allowances in accordance with this 

subpart.

(2) A description of whether a unit is required to monitor and 

report NOX emissions using a continuous emission monitoring 

system (under subpart H of part 75 of this chapter), an excepted 

monitoring system (under appendices D and E to part 75 of this 

chapter), a low mass emissions excepted monitoring methodology 

(under §75.19 of this chapter), or an alternative monitoring 

system (under subpart E of part 75 of this chapter) in 

accordance with §§97.430 through 97.435 may be added to, or 

changed in, a title V permit using minor permit modification 

procedures in accordance with §§70.7(e)(2) and 71.7(e)(1) of 

this chapter, provided that the requirements applicable to the 

described monitoring and reporting (as added or changed, 

respectively) are already incorporated in such permit. This 

paragraph explicitly provides that the addition of, or change 

to, a unit’s description as described in the prior sentence is 

eligible for minor permit modification procedures in accordance 

with §§70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter. 
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(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.

(iii) Copies of all reports, compliance certifications, and 

other submissions and all records made or required under, or to 
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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. This requirement does not change, 

create an exemption from, or or otherwise affect the responsible 

official submission requirements under a title V operating permit 

program in parts 70 and 71 of this chapter. 

(f) Liability. (1) Any provision of the TR NOX Annual Trading 

Program that applies to a TR NOX Annual source or the designated 

representative of a TR NOX Annual source shall also apply to the 

owners and operators of such source and of the TR NOX Annual 

units at the source.

(2) Any provision of the TR NOX Annual Trading Program that 

applies to a TR NOX Annual unit or the designated representative 

of a TR NOX Annual unit shall also apply to the owners and 

operators of such unit.

(g) Effect on other authorities. No provision of the TR NOX

Annual Trading Program or exemption under §97.405 shall be 

construed as exempting or excluding the owners and operators, 

and the designated representative, of a TR NOX Annual source or 

TR NOX Annual unit from compliance with any other provision of 
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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]
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§ 97.410 State NOX Annual trading budgets, new unit set-asides, 

Indian country new unit set-aside, and variability limits.

(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 38,335 728 38

Kansas 30,714 584 31

Kentucky 85,086 3,403 ---

Maryland 16,633 333 ---

Michigan 60,193 1,144 60

Minnesota 29,572 562 30

Missouri 52,374 1,571 ---

Nebraska 26,440 1,824 26

New Jersey 7,266 145 ---

New York 17,543 509 18

North Carolina 50,587 2,985 51

Ohio 92,703 1,854 ---

Pennsylvania 119,986 2,400 ---

South Carolina 32,498 617 32

Tennessee 35,703 714 ---

Texas 133,595 3,874 134

Virginia 33,242 1,662 ---

West Virginia 59,472 2,974 ---
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Wisconsin 31,628 1,866 32

State

NOX Annual 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 71,962 1,439 ---

Georgia 40,540 811 ---

Illinois 47,872 3,830 ---

Indiana 108,424 3,253 ---

Iowa 37,498 712 37

Kansas 25,560 486 26

Kentucky 77,238 3,090 ---

Maryland 16,574 331 ---

Michigan 57,812 1,098 58

Minnesota 29,572 562 30

Missouri 48,717 1,462 ---

Nebraska 26,440 1,824 26

New Jersey 7,266 145 ---

New York 17,543 509 18

North Carolina 41,553 2,452 42

Ohio 87,493 1,750 ---

Pennsylvania 119,194 2,384 ---

South Carolina 32,498 617 32

Tennessee 19,337 387 ---

Texas 133,595 3,874 134

Virginia 33,242 1,662 ---

West Virginia 54,582 2,729 ---

Wisconsin 30,398 1,793 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.
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(b) The States’ one-year variability limits for the State NOX

Annual trading budgets for the control periods in 2012 and 

thereafter are as follows:

State

One-year variability limits

for 2012 and 2013

One-year

variability limits

for 2014 and thereafter

Alabama 7,269 7,196

Georgia 6,201 4,054

Illinois 4,787 4,787

Indiana 10,973 10,842

Iowa 3,834 3,750

Kansas 3,071 2,556

Kentucky 8,509 7,724

Maryland 1,663 1,657

Michigan 6,019 5,781

Minnesota 2,957 2,957

Missouri 5,237 4,872

Nebraska 2,644 2,644

New Jersey 727 727

New York 2,631 2,631

North Carolina 5,059 4,155

Ohio 9,270 8,749

Pennsylvania 11,999 11,919

South Carolina 3,250 3,250

Tennessee 3,570 1,934

Texas 13,360 13,360

Virginia 3,324 3,324

West Virginia 5,947 5,458

Wisconsin 3,163 3,040

§ 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 
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provided in a notice of data availability issued by the 

Administrator. Providing an allocation for a unit in such notice 

does not constitute a determination that the unit is a TR NOX

Annual unit, and not providing an allocation for 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 for each TR NOX
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Annual unit, in accordance with §97.412(a)(1) through (8), 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 are in accordance with §97.412(a)(1) through (8)

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)(1) through (8) and the reasons for accepting or 
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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 

(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 
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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 for each TR NOX Annual unit in accordance with 

§97.412(a)(9) and (10) 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)(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.

(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 for each TR NOX Annual 

unit, in accordance with §97.412(b)(1) through (8), 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 are in accordance with §97.412(b)(1) through (8)

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)(1) through (8) 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 
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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)(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 for each TR NOX Annual unit in accordance with 

§97.412(b)(9) and (10) and §§97.406(b)(2) and 97.430 through 

97.435. By February 15 immediately after the promulgation of 
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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 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. 

(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 §52.37(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 paragraph (b) of this section 

and §97.412, or under a provision of a SIP revision approved 

under §52.37(a)(3), (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 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 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 

§52.37(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 TR 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 

§52.37(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 §52.37(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 provides should be 
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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 
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will not make any deduction to take account of such already 

recorded TR NOX Annual allowances. 

(5) The Administrator will transfer the TR NOX Annual allowances 

that are not recorded, or that are deducted, in accordance with 

paragraphs (c)(2) and (3) of this section to, for a recipient 

under paragraph (c)(1)(i) of this section, the new unit setaside for the State from whose NOX Annual trading budget the TR 

NOX Annual allowances were allocated, or, for a recipient under 

paragraph (c)(1)(ii) of this paragraph, to the State’s new unit 

set-aside or Indian country new unit set-aside from which the TR 

NOX Annual allowances were allocated, for the control period in 

the year of such transfer.

§ 97.412 TR NOX Annual allowance allocations for new units.

(a) For each control period in 2012 and thereafter and for the 

TR NOX Annual units in each State other than those located in 

Indian county, the Administrator will allocate TR NOX Annual 

allowances to the TR NOX Annual units described in paragraph 

(a)(1) of this section and in accordance with paragraphs (a)(2) 

through (9) of this section:

(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:
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(i) TR NOX Annual units that are not allocated an amount (whether 

zero or greater) of TR NOX Annual allowances in the notice of 

data availability issued under §97.411(a)(1);

(ii) TR NOX Annual units whose allocation of an amount (whether 

zero or greater) 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 (whether 

zero or greater) 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) TR NOX Annual units under §97.411(c)(1)(ii) whose allocation 

of an amount (whether zero or greater) 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 setaside for the State for each such control period. Each such new 

unit set-aside will be allocated TR NOX Annual allowances in an 

amount equal to the applicable amount of tons of NOX emissions as 
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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.

(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 non-Indian country portion of 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 for each TR NOX annual unit described in 

paragraph (a)(1) of this section and for each control period 

described in paragraph (a)(3) of this section will be an amount 
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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 

(9) 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 

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 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 

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 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 
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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 

§97.411(b)(1)(i) and (ii), of the amount of TR NOX Annual 

allowances allocated under paragraphs (a)(1) through (8) 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 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 (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 described in the notice of 

data availability required under §97.411(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 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.

(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 for 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 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 paragraph 

(a)(9) of this section for such control period, any unallocated 
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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 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) and (iv), of the amount of TR NOX Annual 

allowances allocated for such control period to each TR NOX

Annual unit eligible for such allocation.

(b) For each control period in 2012 and thereafter and for the 

TR NOX Annual units located in Indian country in each State, the 

Administrator will allocate TR NOX Annual allowances to the TR 
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NOX Annual units described in paragraph (b)(1) of this section 

and in accordance with paragraphs (b)(2) through (9) of this 

section:

(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 (whether 

zero or greater) of TR NOX Annual allowances in the notice of 

data availability issued under §97.411(a)(1); or

(ii) TR NOX Annual units under §97.411(c)(1)(ii) whose allocation 

of an amount (whether zero or greater) 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 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).
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(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 for each TR NOX annual unit described in 

paragraph (b)(1) 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 

(9) 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 the State for such 

control period.

(6) If the amount of TR NOX Annual allowances in the Indian 

country new unit set-aside for the State for such control period 
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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)(1) through (8) 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 
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unallocated TR NOX Annual allowances remain in the Indian country 

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 (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 described 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 
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allowances determined for each such TR NOX Annual unit under 

paragraph (b)(9)(i) of this section.

(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 this section, then the Administrator will allocate 

for 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 setaside 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 paragraph 

(b)(9) 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) Allocate 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 §52.37(a)(4) 

or (5), include such unallocated TR NOX Annual allowances in the 
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portion of the State TR 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) and (iv), of the amount of TR NOX Annual 

allowances allocated for such control period to each TR NOX

Annual unit eligible for such allocation.

§ 97.413 Authorization of designated representative and 

alternate designated representative.

(a) Except as provided under §97.415, each TR NOX Annual source, 

including all TR NOX Annual units at the source, shall have one 

and only one designated representative, with regard to all 

matters under the TR NOX Annual Trading Program.

(1) The designated representative shall be selected by an 

agreement binding on the owners and operators of the source and 

all TR NOX Annual units at the source and shall act in accordance 

with the certification statement in §97.416(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete 

certificate of representation under §97.416:
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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 NOX Annual unit at the source in all 

matters pertaining to the TR NOX Annual Trading Program, 

notwithstanding any agreement between the designated 

representative and such owners and operators; and

(ii) The owners and operators of the source and each TR NOX

Annual unit at the source shall be bound by any decision or 

order issued to the designated representative by the 

Administrator regarding the source or any such unit.

(b) Except as provided under §97.415, each TR NOX Annual source 

may have one and only one alternate designated representative, 

who may act on behalf of the designated representative. The 

agreement by which the alternate designated representative is 

selected shall include a procedure for authorizing the alternate 

designated representative to act in lieu of the designated 

representative.

(1) The alternate designated representative shall be selected by 

an agreement binding on the owners and operators of the source 

and all TR NOX Annual units at the source and shall act in 
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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 theterm “common designated representative”) 

is used in this subpart, the term shall be construed to include 

the designated representative or any alternate designated 

representative.

§ 97.414 Responsibilities of designated representative and 

alternate designated representative.
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(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 
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submission has been made, signed, and certified in accordance 

with paragraph (a) of this section and §97.418.

§ 97.415 Changing designated representative and alternate 

designated representative; changes in owners and operators; 

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 
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superseding certificate of representation shall be binding on 

the new alternate designated representative, the designated 

representative, and the owners and operators of the TR NOX Annual 

source and the TR NOX Annual units at the source.

(c) Changes in owners and operators. (1) In the event an owner 

or operator of a TR NOX Annual source or a TR NOX Annual unit 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.
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(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 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.
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(a) A complete certificate of representation for a designated 

representative or an alternate designated representative shall 

include the following elements in a format prescribed by the 

Administrator:

(1) Identification of the TR NOX Annual source, and each TR NOX

Annual unit at the source, for which the certificate of 

representation is submitted, including source name, source 

category and NAICS code (or, in the absence of a NAICS code, an 

equivalent code), State, plant code, county, latitude and 

longitude, unit identification number and type, identification 

number and nameplate capacity (in MWe, rounded to the nearest 

tenth) of each generator served by each such unit, and actual or 

projected date of commencement of commercial operation and 

including 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 Annual 

source and of each TR NOX Annual unit at the source.

(4) The following certification statements by the designated 

representative and any alternate designated representative—

(i) “I certify that I was selected as the designated 

representative or alternate designated representative, as 

applicable, by an agreement binding on the owners and operators 

of the source and each TR NOX Annual unit at the source.”

(ii) “I certify that I have all the necessary authority to carry 

out my duties and responsibilities under the TR NOX Annual 

Trading Program on behalf of the owners and operators of the 

source and of each TR NOX Annual unit at the source and that each 

such owner and operator shall be fully bound by my 

representations, actions, inactions, or submissions and by any 

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 
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Page 847 of 1339

designated representative’, as applicable, and of the agreement 

by which I was selected to each owner and operator of the source 

and of each TR NOX Annual unit at the source; and TR NOX Annual 

allowances and proceeds of transactions involving TR NOX Annual 

allowances will be deemed to be held or distributed in 

proportion to each holder's legal, equitable, leasehold, or 

contractual reservation or entitlement, except that, if such 

multiple holders have expressly provided for a different 

distribution of TR NOX Annual allowances by contract, TR NOX

Annual allowances and proceeds of transactions involving TR NOX

Annual allowances will be deemed to be held or distributed in 

accordance with the contract.”

(5) The signature of the designated representative and any 

alternate designated representative and the dates signed.

(b) Unless otherwise required by the Administrator, documents of 

agreement referred to in the certificate of representation shall 

not be submitted to the Administrator. The Administrator shall 

not be under any obligation to review or evaluate the 

sufficiency of such documents, if submitted.

§ 97.417 Objections concerning designated representative and 

alternate designated representative.
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(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 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.
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(a) A designated representative may delegate, to one or more 

natural persons, his or her authority to make an electronic 

submission to the Administrator provided for or required under 

this subpart.

(b) An alternate designated representative may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(c) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph (a) 

or (b) of this section, the designated representative or 

alternate designated representative, as appropriate, must submit 

to the Administrator a notice of delegation, in a format 

prescribed by the Administrator, that includes the following 

elements:

(1) The name, address, e-mail address, telephone number, and 

facsimile transmission number (if any) of such designated 

representative or alternate designated representative;

(2) The name, address, e-mail address, telephone number, and 

facsimile transmission number (if any) of each such natural 

person (referred to in this section as an “agent”);
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(3) For each such natural person, a list of the type or types of 

electronic submissions under paragraph (a) or (b) of this 

section for which authority is delegated to him or her; and

(4) The following certification statements by such designated 

representative or alternate designated representative:

(i) “I agree that any electronic submission to the Administrator 

that is made by an agent identified in this notice of delegation 

and of a type listed for such agent in this notice of delegation 

and that is made when I am a designated representative or 

alternate designated representative, as appropriate, and before 

this notice of delegation is superseded by another notice of 

delegation under 40 CFR 97.418(d) shall be deemed to be an 

electronic submission by me.”

(ii) “Until this notice of delegation is superseded by another 

notice of delegation under 40 CFR 97.418(d), I agree to maintain 

an e-mail account and to notify the Administrator immediately of 

any change in my e-mail address unless all delegation of 

authority by me under 40 CFR 97.418 is terminated.”.

(d) A notice of delegation submitted under paragraph (c) of this

section shall be effective, with regard to the designated 

representative or alternate designated representative identified 

in such notice, upon receipt of such notice by the Administrator 
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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 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 
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the alternate authorized account representative respectively of 

the compliance account.

(b) Assurance accounts. As provided in §97.425(b)(3), the 

Administrator will establish assurance accounts for the owners 

and operators and States specified in the notice required under 

§97.425(b)(2)(iii)(B). 

(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. 

(B) The agreement by which the alternate authorized account 

representative is selected shall include a procedure for 
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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 
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NOX Annual allowances held in the general account. I certify that 

I have all the necessary authority to carry out my duties and 

responsibilities under the TR NOX Annual Trading Program on 

behalf of such persons and that each such person shall be fully 

bound by my representations, actions, inactions, or submissions 

and by any 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:
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(A) The authorized account representative of the general account 

shall be authorized and shall represent and, by his or her 

representations, actions, inactions, or submissions, legally 

bind each person who has an ownership interest with respect to 

TR NOX Annual allowances held in the general account in all 

matters pertaining to the TR NOX Annual Trading Program, 

notwithstanding any agreement between the authorized account 

representative and such person. 

(B) Any alternate authorized account representative shall be 

authorized, and any representation, action, inaction, or 

submission by any alternate authorized account representative 

shall be deemed to be a representation, action, inaction, or 

submission by the authorized account representative.

(C) Each person who has an ownership interest with respect to TR 

NOX Annual allowances held in the general account shall be bound 

by any 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 
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alternate authorized account representative for the persons 

having an ownership interest with respect to TR NOX Annual 

allowances held in the general account. Each such submission 

shall include the following certification statement by the 

authorized account representative or any alternate authorized 

account representative: “I am authorized to make this submission 

on behalf of the persons having an ownership interest with 

respect to the TR NOX Annual allowances held in the general 

account. I certify under penalty of law that I have personally 

examined, and am familiar with, the statements and information 

submitted in this document and all its attachments. Based on my 

inquiry of those individuals with primary responsibility for 

obtaining the information, I certify that the statements and 

information are to the best of my knowledge and belief true, 

accurate, and complete. I am aware that there are significant 

penalties for submitting false statements and information or 

omitting required statements and information, including the 

possibility of fine or imprisonment.”

(iii) Except in this section, whenever the term “authorized 

account representative” is used in this subpart, the term shall 

be construed to include the authorized account representative or 

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

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 
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persons with an ownership interest with respect to the TR NOX

Annual allowances in the general account.

(iii)(A) In the event a person having an ownership interest with 

respect to TR NOX Annual allowances in the general account is not 

included in the list of such persons in the application for a 

general account, such person shall be deemed to be subject to 

and bound by the application for a general account, the 

representation, actions, inactions, and submissions of the 

authorized account representative and any alternate authorized 

account representative of the account, and the decisions and 

orders of the Administrator, as if the person were included in 

such list.

(B) Within 30 days after any change in the persons having an 

ownership interest with respect to NOX Annual allowances in the 

general account, including the addition 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 
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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.

(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.
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(5) Delegation by authorized account representative and 

alternate authorized account representative. (i) An authorized 

account representative of a general account may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(ii) An alternate authorized account representative of a general 

account may delegate, to one or more natural persons, his or her 

authority to make an electronic submission to the Administrator 

provided for or required under this subpart.

(iii) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph 

(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 97.420(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 delegation under 40 CFR 97.420(c)(5)(iv), I 

agree to maintain an e-mail account and to notify the 

Administrator immediately of any change in my e-mail address 
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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)(i) The authorized account representative or alternate 

authorized account representative of a general account may 

submit to the Administrator a request to close the account. 

Such request shall include a correctly submitted TR NOX Annual 
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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.

(d) Responsibilities of authorized account representative and 

alternate authorized account representative. After the 

establishment of a compliance account or general account, the 
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Administrator will accept or act on a submission pertaining to 

the account, including, but not limited to, submissions 

concerning the deduction or transfer of TR NOX Annual allowances 

in the account, only if the submission has been made, signed, 

and certified in accordance with §§97.414(a) and 97.418 or 

paragraphs (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 
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the requirements of §52.37(a)(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 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.
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(c) By July 1, 2013, , the Administrator will record in each TR 

NOX Annual source's compliance account the TR NOX Annual 

allowances allocated for the TR NOX Annual units at the source in 

accordance with §97.411(a), or with a SIP revision approved 

under §52.37(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 for the TR NOX Annual units at the source in accordance 

with §97.411(a), or with a SIP revision approved under 

§52.37(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 for the TR NOX Annual units at the source in accordance 

with §97.411(a), or with a SIP revision approved under 

§52.37(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 for the 

TR NOX Annual units at the source in accordance with §97.411(a), 
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or with a SIP revision approved under §52.37(a)(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 Annual source's 

compliance account the TR NOX Annual allowances allocated for the 

TR NOX Annual units at the source in accordance with §97.412(a), 

or with a SIP revision approved under §52.37(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 for the 

TR NOX Annual units at the source in accordance with §97.412(b) 

for the control period in the year of the applicable recordation 

deadline under this paragraph.

(i) By the date on which any allocation, other than an 

allocation described in paragraphs (a) through (h) of this 

section, of TR NOX Annual allowances to a recipient is made by or 

submitted to the Administrator in accordance with §97.411 or 

§97.412 or with a SIP revision approved under §52.37(a)(4) or 
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(5) of this chapter, the Administrator will record such 

allocation in the appropriate Allowance Management System 

account. 

(j) To the extent a SIP revision approved under §52.37(a)(4) or 

(5) of this chapter provides for one or more auctions, in lieu 

of allocation, of TR NOX Annual allowances for a control period 

in a given year, the Administrator will record in the 

appropriate Allowance Management System account under such SIP 

revision the amount of TR NOX Annual allowances purchased at such 

auctions by the deadline, specified in paragraphs (a) through 

(h) of this section, for recordation of an allocation for the 

control period in such year. 

(k) When recording the allocation or auction of TR NOX Annual 

allowances for a TR NOX Annual unit 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.

§ 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. 
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(b) A TR NOX Annual allowance transfer shall be correctly 

submitted if: 

(1) The transfer includes the following elements, in a format 

prescribed by the Administrator:

(i) The account numbers established by the Administrator for 

both the transferor and transferee accounts;

(ii) The serial number of each TR NOX Annual allowance that is in 

the transferor account and is to be transferred; and

(iii) The name and signature of the authorized account 

representative of the transferor account and the date signed; 

and

(2) When the Administrator attempts to record the transfer, the 

transferor account includes each TR NOX Annual allowance 

identified by serial number in the transfer. 

§ 97.423 Recordation of TR NOX Annual allowance transfers.

(a) Within 5 business days (except as provided in paragraph (b) 

of this section) of receiving a TR NOX Annual allowance transfer

that is correctly submitted under §97.422, the Administrator 

will record a TR NOX Annual allowance transfer by moving each TR 
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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 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 
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§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:

(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 
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whether the source meets the TR NOX Annual emissions limitation 

for such control period, as follows:

(1) Until the amount of TR NOX Annual allowances deducted equals 

the number of tons of total NOX emissions from all TR NOX Annual 

units at the source for such control period; or

(2) If there are insufficient TR NOX Annual allowances to 

complete the deductions in paragraph (b)(1) of this section, 

until no more TR NOX Annual allowances available under paragraph 

(a) of this section remain in the compliance account.

(c)(1) Identification of TR NOX Annual allowances by serial 

number. The authorized account representative for a source's 

compliance account may request that specific TR NOX Annual 

allowances, identified by serial number, in the compliance 

account be deducted for emissions or excess emissions for a 

control period in 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 
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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 Administrator will deduct from the 

source's compliance account an amount of TR NOX Annual 

allowances, allocated for the control period in the immediately 

following year, equal to two times the number of tons of the 

source's excess emissions.
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(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 only if the TR NOX Annual 

allowances: 

(1) Were allocated for such control period or a control period 

in a prior 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 under paragraph (b)(3)

of this section, as of the deadline established in paragraph 

(b)(5) of this section. 

(b) Deductions for compliance. The Administrator will deduct TR 

NOX Annual allowances available under paragraph (a) of this 

section for compliance with the TR NOX Annual assurance 
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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, separately for each State, the total NOX emissions 

from all TR NOX Annual units at TR NOX Annual sources in the 

State during the control period in the year before the year of 

this calculation deadline and the amount, if any, by which such 

total 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 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 
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each 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 each common designated representative (authorized as of the 

allowance transfer deadline for such control period) for a group 

of one or more TR NOX Annual sources and units in the State and 

for such control period, 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, 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 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 
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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 accepting or 

rejecting any objections submitted in accordance with paragraph 

(b)(2)(iii)(A) of this section.
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(3) For any State identified 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 identified, 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 having a common designated 

representative (as of the allowance transfer deadline 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 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 sources, 
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units and 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 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 States 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 involved, provided that such litigation 

under part 78 of this chapter, or the proceeding under part 78 
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of this chapter that resulted in the decision appealed in such 

litigation under section 307 of the Clean Air Act, was initiated 

no later than 30 days after promulgation of such notice required 

in paragraph (b)(2)(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 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 (b)(6)(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 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 

under paragraph (b)(3) of this section. The owners’ and 

operaters’ 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, 
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and State under paragraph (b)(3) of this section, a total amount 

of TR NOX Annual allowances 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, or recorded under paragraph 

(b)(6)(iii)(B) 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 such control period or a control period in a prior year. 

§ 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.
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The owners and operators, and to the extent applicable, the 

designated representative, of a TR NOX Annual unit, shall comply 

with the monitoring, recordkeeping, and reporting requirements 

as provided in this subpart and subpart H of part 75 of this 

chapter. For purposes of applying such requirements, the 

definitions in §97.402 and in §72.2 of this chapter shall apply, 

the terms “affected unit,” “designated representative,” and 

“continuous emission monitoring system” (or “CEMS”) in part 75 

of this chapter shall be deemed to refer to the terms “TR NOX

Annual unit,“ “designated representative,” and “continuous 

emission monitoring system” (or “CEMS”) respectively as defined 

in §97.402, and the term “newly affected unit” shall be deemed 

to mean “newly affected TR NOX Annual unit”. The owner or 

operator of a unit that is not a TR NOX Annual unit but that is 

monitored under §75.72(b)(2)(ii) of this chapter shall comply 

with the same monitoring, recordkeeping, and reporting 

requirements as a TR NOX Annual unit.

(a) Requirements for installation, certification, and data 

accounting. The owner or operator of each TR NOX Annual unit 

shall:

(1) Install all monitoring systems required under this subpart 

for monitoring NOX mass emissions and individual unit heat input 

(including all systems required to monitor NOX emission rate, NOX
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concentration, stack gas moisture content, stack gas flow rate, 

CO2 or O2 concentration, and fuel flow rate, as applicable, in 

accordance with §§75.71 and 75.72 of this chapter);

(2) Successfully complete all certification tests required under 

§97.431 and meet all other requirements of this subpart and part 

75 of this chapter applicable to the monitoring systems under 

paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the 

monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) 

of this section, the owner or operator shall meet the monitoring 

system certification and other requirements of paragraphs (a)(1) 

and (2) of this section on or before the following dates and 

shall record, report, and quality-assure the data from the 

monitoring systems under paragraph (a)(1) of this section on and 

after the following dates.

(1) For the owner or operator of a TR NOX Annual unit that 

commences commercial operation before July 1, 2011, January 1, 

2012; 
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(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 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
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(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, 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 
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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 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 
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provides emission data for the same pollutant or parameter as 

the retired or discontinued monitoring system; or

(iii) The designated representative submits notification of the 

date of certification testing of a replacement monitoring system 

for the retired or discontinued monitoring system in accordance 

with §97.431(d)(3)(i).

(e) Long-term cold storage. The owner or operator of a TR NOX

Annual unit is subject to the applicable provisions of §75.4(d) 

of this chapter concerning units in long-term cold storage.

§ 97.431 Initial monitoring system certification and 

recertification procedures.

(a) The owner or operator of a TR NOX Annual unit shall be exempt 

from the initial certification requirements of this section for 

a monitoring system under §97.430(a)(1) if the following 

conditions are met:

(1) The monitoring system has been previously certified in 

accordance with part 75 of this chapter; and

(2) The applicable quality-assurance and quality-control 

requirements of §75.21 of this chapter and appendices B, D, and 

E to part 75 of this chapter are fully met for the certified 

monitoring system described in paragraph (a)(1) of this section.
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(b) The recertification provisions of this section shall apply 

to a monitoring system under §97.430(a)(1) that is exempt from 

initial certification requirements under paragraph (a) of this 

section.

(c) If the Administrator has previously approved a petition 

under §75.17(a) or (b) of this chapter for apportioning the NOX

emission rate measured in a common stack or a petition under 

§75.66 of this chapter for an alternative to a requirement in 

§75.12 or §75.17 of this chapter, the designated representative 

shall resubmit the petition to the Administrator under §97.435 

to determine whether the approval applies under the TR NOX Annual 

Trading Program.

(d) Except as provided in paragraph (a) of this section, the 

owner or operator of a TR NOX Annual unit shall comply with the 

following initial certification and recertification procedures 

for a continuous monitoring system (i.e., a continuous emission 

monitoring system and an excepted monitoring system under 

appendices D and E to part 75 of this chapter) under 

§97.430(a)(1). The owner or operator of a unit that qualifies 

to use the low mass emissions excepted monitoring methodology 

under §75.19 of this chapter or that qualifies to use an 

alternative monitoring system under subpart E of part 75 of this 
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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 operator shall recertify the 

monitoring system in accordance with §75.20(b) of this chapter. 

Furthermore, whenever the owner or operator makes a replacement, 
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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 
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“certification” and “initial certification” are replaced by the 

word “recertification” and the word “certified” is replaced by 

with the word “recertified”. 

(i) Notification of certification. The designated 

representative shall submit to the appropriate EPA Regional

Office and the Administrator written notice of the dates of 

certification testing, in accordance with §97.433.

(ii) Certification application. The designated representative 

shall submit to the Administrator a certification application 

for each monitoring system. A complete certification application 

shall include the information specified in §75.63 of this 

chapter.

(iii) Provisional certification date. The provisional 

certification date for a monitoring system shall be determined 

in accordance with §75.20(a)(3) of this chapter. A 

provisionally certified monitoring system may be used under the 

TR NOX Annual Trading Program for a period not to exceed 120 days 

after receipt by the Administrator of the complete certification 

application for the monitoring system under paragraph (d)(3)(ii) 

of this section. Data measured and recorded by the 

provisionally certified monitoring system, in accordance with 

the requirements of part 75 of this chapter, will be considered 
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valid quality-assured data (retroactive to the date and time of 

provisional certification), provided that the Administrator does 

not invalidate the provisional certification by issuing a notice 

of disapproval within 120 days of the date of receipt of the 

complete certification application by the Administrator.

(iv) Certification application approval process. The 

Administrator will issue a written notice of approval or 

disapproval of the certification application to the owner or 

operator within 120 days of receipt of the complete 

certification application under paragraph (d)(3)(ii) of this 

section. In the event the Administrator does not issue such a 

notice within such 120-day period, each monitoring system that 

meets the applicable performance requirements of part 75 of this 

chapter and is included in the certification application will be 

deemed certified for use under the TR NOX Annual Trading Program.

(A) Approval notice. If the certification application is 

complete and shows that each monitoring system meets the 

applicable performance requirements of part 75 of this chapter, 

then the Administrator will issue a written notice of approval 

of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification 

application is not complete, then the Administrator will issue a 
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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 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).
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(v) Procedures for loss of certification. If the Administrator 

issues a notice of disapproval of a certification application 

under paragraph (d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under paragraph 

(d)(3)(iv)(D) of this section, then:

(A) The owner or operator shall substitute the following values, 

for each disapproved monitoring system, for each hour of unit 

operation during the period of invalid data specified under 

§75.20(a)(4)(iii), §75.20(g)(7), or §75.21(e) of this chapter 

and continuing until the applicable date and hour specified 

under §75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) 

system, the maximum potential NOX emission rate, as defined in 

§72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and 

disapproved flow monitor, respectively, the maximum potential 

concentration of NOX and the maximum potential flow rate, as 

defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 

of this chapter.

(3) For a disapproved moisture monitoring system and disapproved 

diluent gas monitoring system, respectively, the minimum 

potential moisture percentage and either the maximum potential 
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CO2 concentration or the minimum potential O2 concentration (as 

applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 

of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum 

potential fuel flow rate, as defined in section 2.4.2.1 of 

appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under 

appendix E to part 75 of this chapter, the fuel-specific maximum 

potential NOX emission rate, as defined in §72.2 of this chapter.

(B) The designated representative shall submit a notification of 

certification retest dates and a new certification application 

in accordance with paragraphs (d)(3)(i) and (ii) of this 

section.

(C) The owner or operator shall repeat all certification tests 

or other requirements that were failed by the monitoring system, 

as indicated in the Administrator's notice of disapproval, no 

later than 30 unit operating days after the date of issuance of 

the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low 

mass emissions (LME) excepted methodology under §75.19 of this 

chapter shall meet the applicable certification and 
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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.

§ 97.432 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 
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under §97.431 or the applicable provisions of part 75 of this 

chapter, both at the time of the initial certification or 

recertification application submission and at the time of the 

audit, the Administrator will issue a notice of disapproval of 

the certification status of such monitoring system. For the 

purposes of this paragraph, an audit shall be either a field 

audit or an audit of any information submitted to the 

Administrator or any 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.
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§ 97.434 Recordkeeping and reporting.

(a) General provisions. The designated representative shall 

comply with all recordkeeping and reporting requirements in 

paragraphs (b) through (e) of this section, the applicable 

recordkeeping and reporting requirements under §75.73 of this 

chapter, and the requirements of §97.414(a).

(b) Monitoring plans. The owner or operator of a TR NOX Annual 

unit shall comply with requirements of §75.73(c) and (e) of this 

chapter.

(c) Certification applications. The designated representative 

shall submit an application to the Administrator within 45 days 

after completing all initial certification or recertification 

tests required under §97.431, including the information required 

under §75.63 of this chapter.

(d) Quarterly reports. The designated representative shall 

submit quarterly reports, as follows:

(1) The designated representative shall report the NOX mass 

emissions data and heat input data for the TR NOX Annual unit, in 

an electronic quarterly report in a format prescribed by the 

Administrator, for each calendar quarter beginning with:
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(i) For a unit that commences commercial operation before July 

1, 2011, the calendar quarter covering January 1, 2012 through 

March 31, 2012; 

(ii) For a unit that commences commercial operation on or after 

July 1, 2011, the calendar quarter corresponding to the earlier 

of the date of provisional certification or the applicable 

deadline for initial certification under §97.430(b), unless that 

quarter is the third or fourth quarter of 2011, in which case 

reporting shall commence in the quarter covering January 1, 2012 

through March 31, 2012;

(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.
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(4) The Administrator may review and conduct independent audits 

of any quarterly report in order to determine whether the 

quarterly report meets the requirements of this subpart and part 

75 of this chapter, including the requirement to use substitute 

data. 

(i) The Administrator will notify the designated representative 

of any determination that the quarterly report fails to meet any 

such requirements and specify in such notification any 

corrections that the Administrator believes are necessary to 

make through resubmission of the quarterly report and a 

reasonable time period within which the designated 

representative must respond. Upon request by the designated 

representative, the Administrator may specify reasonable 

extensions of such time period. Within the time period 

(including any such extensions) specified by the Administrator, 

the designated representative shall resubmit the quarterly 

report with the corrections specified by the Administrator, 

except to the extent the designated representative provides 

information demonstrating that a specified correction is not 

necessary because the quarterly report already meets the 

requirements of this subpart and part 75 of this chapter that 

are relevant to the specified correction.
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(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 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.
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§ 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;

(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
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(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.

97.506 Standard requirements.

97.507 Computation of time.

97.508 Administrative appeal procedures.
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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 for new units.

97.513 Authorization of designated representative and alternate 

designated representative.

97.514 Responsibilities of designated representative and 

alternate designated representative.

97.515 Changing designated representative and alternate 

designated representative; changes in owners and operators.

97.516 Certificate of representation.

97.517 Objections concerning designated representative and 

alternate designated representative.

97.518 Delegation by designated representative and alternate 

designated representative.

97.519 [Reserved]
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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.

97.533 Notifications concerning monitoring.

97.534 Recordkeeping and reporting.
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97.535 Petitions for alternatives to monitoring, recordkeeping, 

or reporting requirements.

Subpart AAAAA—TR NOX Ozone Season Trading Program 

§ 97.501 Purpose.

This subpart sets forth the general, designated representative, 

allowance, and monitoring provisions for the Transport Rule (TR) 

NOX Ozone Season Trading Program, under section 110 of the Clean 

Air Act and §52.37 of this chapter, as a means of mitigating 

interstate transport of fine particulates and nitrogen oxides.

§ 97.502 Definitions.

The terms used in this subpart shall have the meanings set forth 

in this section as follows:

Acid Rain Program means a 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) of the United States 
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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 §52.37(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, with regard to 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 
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complying with the source's TR NOX Ozone Season emissions 

limitation for such control period in accordance with §§97.506 

and 97.524.

Alternate designated representative means, with regard to 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, 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. 
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Authorized account representative means, with regard to a 

general account, the natural person who is authorized, in 

accordance with this subpart, to transfer and otherwise dispose 

of TR NOX Ozone Season allowances held in the general account 

and, with regard to a TR NOX Ozone Season source’s compliance 

account, the designated representative of the source.

Automated data acquisition and handling system or DAHS means the 

component of the continuous emission monitoring system, or other 

emissions monitoring system approved for use under this subpart, 

designed to interpret and convert individual output signals from 

pollutant concentration monitors, flow monitors, diluent gas 

monitors, and other component parts of the monitoring system to 

produce a continuous record of the measured parameters in the 

measurement units required by this subpart. 

Biomass means—

(1) Any organic material grown for the purpose of being 

converted to energy;

(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 
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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 

vice-president or the corporation in charge of a principal 

business function or any other person who performs similar 

policy- or decision-making functions for the corporation;

(2) For a partnership or sole proprietorship, a general partner 

or the proprietor respectively; or

(3) For a local government entity or State, federal, or other 

public agency, a principal executive officer or ranking elected 

official.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq. 

Coal means “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. 
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Cogeneration unit means a stationary, fossil-fuel-fired boiler 

or stationary, fossil-fuel-fired combustion turbine—

(1) Operating as part of a cogeneration system; and

(2) Producing on an Ozone Season average basis during the later 

of 2005 or the 12-month period starting on the date that the 

unit first produces electricity and during each calendar year 

after the later of 2005 or the calendar year in which the unit 

first produces electricity—

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less than 5 percent of total 

energy output; and

(B) Useful power that, when added to one-half of useful thermal 

energy produced, is not less 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;
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(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:

(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
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(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 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 
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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, 
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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 a designated 

representative where 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.

Common designated representative’s assurance level means, with

regard to a specific common designated representative and a 

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 one-year variability limit 

for the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative:

(1) With regard to a total amount of NOX emissions from all TR 

NOX Ozone Season units in a State during a control period in a 

given year, the total tonnage of NOX emissions during such 

control period from a group of one or more TR NOX Ozone Season
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units located in the State and having the common designated 

representative as of the allowance transfer deadline for such 

control period; 

(2) With regard to a State NOX Ozone Season trading budget for a 

control period in a given year, 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 having the common designated representative as of the 

allowance transfer deadline 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 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 §52.37(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 one-year variability 

limit under §97.510(b) for such control period and divided by 

such State NOX Ozone Season trading budget; 

(3) Provided that, in the case of a unit that operates during, 

but has no amount of TR NOX Ozone Season allowances allocated 
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under §§97.511 and 97.512 for, a control period in a given year, 

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 0.89

(if the unit is a boiler combusting any amount of coal or coalderived fuel during such control period), 0.22 (if the unit is a 

simple combustion turbine during such control period), 0.73 (if 

the unit is a combined cycle turbine during such control 

period), 0.55 (if the unit is a boiler combusting only fuel oil 

or natural gas during such control period), or 0.75 (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 for the TR NOX Ozone Season units at the source are 

recorded and in which are held any TR NOX Ozone Season allowances 

available for use for a control period in a given year in 
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complying 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 
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gas (CO2 or O2) monitor, and an automated data acquisition and 

handling system and providing a permanent, continuous record of 

NOX concentration, in parts per million (ppm), diluent gas 

concentration, in percent CO2 or O2, and NOX emission rate, in 

pounds per million British thermal units (lb/mmBtu);

(4) A moisture monitoring system, as defined in §75.11(b)(2) of 

this chapter and providing a permanent, continuous record of the 

stack gas moisture content, in percent H2O;

(5) A CO2 monitoring system, consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor plus suitable 

mathematical equations from which the CO2 concentration is 

derived) and an automated data acquisition and handling system 

and providing a permanent, continuous record of CO2 emissions, in 

percent CO2; and

(6) An O2 monitoring system, consisting of an O2 concentration 

monitor and an automated data acquisition and handling system 

and providing a permanent, continuous record of O2, in percent 

O2.

Control period means the period starting May 1 of a calendar 

year, except as provided in §97.506(c)(3), and ending on 

September 30 of the same year, inclusive.
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Designated representative means, with regard to a TR NOX Ozone 

Season source and each TR NOX Ozone Season unit at the source, 

the natural person who is authorized by the owners and operators 

of the source and all such units at the source, in accordance 

with this subpart, to represent and legally bind each owner and

operator in matters pertaining to the TR NOX Ozone Season Trading 

Program. If the TR NOX Ozone Season source is also subject to 

the Acid Rain Program, TR NOX Annual Trading Program, TR SO2 Group 

1 Trading Program, or TR SO2 Group 2 Trading Program, then this 

natural person shall be the same natural person as the 

designated representative, as defined in 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 
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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

(2) For purposes of applying the limitation on “average Ozone 

Season 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.

Fuel oil means “fuel oil” as defined in §72.2 of this chapter.

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 
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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.

Heat input rate means, for a unit, the amount of heat input (in 

mmBtu) divided by unit operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input attributed to the fuel 

(in mmBtu) divided by the unit operating time (in hr) during 

which the unit combusts the fuel.

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, as defined in 18 U.S.C. 1151:

(1) All land within the limits of any Indian reservation under 

the jurisdiction of the United States Government, 
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notwithstanding the issuance of any patent, and, including 

rights-of-way running through the reservation;

(2) All dependent Indian communities within the borders of the 

United States whether within the original or subsequently 

acquired territory thereof, and whether within or without the 

limits of a state; and 

(3) All Indian allotments, the Indian titles to which have not 

been extinguished, including rights-of-way running through the 

same.

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 
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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 
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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 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, with regard to 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, with regard to a TR NOX Ozone Season source or a TR 

NOX Ozone Season unit at a source respectively, any of the 

following persons:
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(1) Any holder of any portion of the legal or equitable title in 

a TR NOX Ozone Season unit at the source or the TR NOX Ozone 

Season unit;

(2) Any holder of a leasehold interest in a TR NOX Ozone Season

unit at the source or the TR NOX Ozone Season unit, provided 

that, unless expressly provided for in a leasehold agreement, 

“owner” shall not include a passive lessor, or a person who has 

an equitable interest through such lessor, whose rental payments 

are not based (either directly or indirectly) on the revenues or 

income from such TR NOX Ozone Season unit; 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 
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3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 

hr/yr.

Receive or receipt of means, when referring to the 

Administrator, to come into possession of a document, 

information, or correspondence (whether sent in hard copy or by 

authorized electronic transmission), as indicated in an official 

log, or by a notation made on the document, information, or 

correspondence, by the Administrator in the regular course of 

business.

Recordation, record, or recorded means, with regard to TR NOX

Ozone Season allowances, the moving of TR NOX Ozone Season

allowances by the Administrator into, out of, or between 

Allowance Management System accounts, for purposes of 

allocation, 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).
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Sequential use of energy means:

(1) For a topping-cycle unit, the use of reject heat from 

electricity production in a useful thermal energy application or 

process; or

(2) For a bottoming-cycle unit, the use of reject heat from 

useful thermal energy application or process in electricity 

production.

Serial number means, for a TR NOX Ozone Season allowance, the 

unique identification number assigned to each TR NOX Ozone Season

allowance by the Administrator.

Solid waste incineration unit means a stationary, fossil-fuelfired 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. 
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State means one of the States that is subject to the TR NOX Ozone 

Season Trading Program pursuant to §52.37(b) of this chapter

and, when used to refer to a geographic area, includes Indian 

country located within the borders of such State.

Submit or serve means to send or transmit a document, 

information, or correspondence to the person specified in 

accordance with the applicable regulation:

(1) In person;

(2) By United States Postal Service; or

(3) By other means of dispatch or transmission and delivery;

(4) Provided that compliance with any “submission” or “service” 

deadline shall be determined by the date of dispatch, 

transmission, or mailing and not the date of receipt.

Topping-cycle unit means a unit in which the energy input to the 

unit is first used to produce useful power, including 

electricity, where at least some of the reject heat from the 

electricity production is then used to provide useful thermal 

energy.

Total energy input means, for a unit, total energy of all forms 

supplied to the unit, excluding energy produced by the unit. 
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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 §52.37(a) of this 

chapter (including such a program that is revised in a SIP 

revision approved by the Administrator under §52.37(a)(3) or (4) 

of this chapter) or with a SIP revision approved by the 

Administrator under §52.37(a)(5) of this chapter, as a means of 

mitigating interstate transport of fine particulates and NOX.
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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 §52.37(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). 

TR NOX Ozone Season allowances held or hold TR NOX Ozone Season

allowances means the TR NOX Ozone Season allowances treated as 

included in an Allowance Management System account as of a 

specified point in time because at that time they:

(1) Have been recorded by the Administrator in the account or 

transferred into the account by a correctly submitted, but not 
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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 §52.37(b) of this chapter

(including such a program that is revised by a State in a SIP 

revision approved by the Administrator under §52.37(b)(3) or (4) 

of this chapter) or with a SIP revision approved by the 

Administrator under §52.37(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 52.38(b) of this 

chapter (including such a program that is revised by a State in 

a SIP revision approved by the Administrator under §52.38(d) or 

(e) of this chapter) or with a SIP revision approved by the 

Administrator under §52.38(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 52.38(c) of this 

chapter (including such a program that is revised by a State in 

a SIP revision approved by the Administrator under §52.38(g) or 

(h) of this chapter) or with a SIP revision approved by the 

Administrator under §52.38(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, 

fossil-fuel-fired combustion device. A unit that undergoes a 

physical change or is moved to a different location or source 
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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;

(2) Used in a heating application (e.g., space heating or 

domestic hot water heating); or
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(3) Used in a space cooling application (i.e., in an absorption 

chiller).

Utility power distribution system means the portion of an 

electricity grid owned or operated by a utility and dedicated to 

delivering electricity to customers.

§ 97.503 Measurements, abbreviations, and acronyms.

Measurements, abbreviations, and acronyms used in this subpart 

are defined as follows:

Btu—British thermal unit

CO2—carbon dioxide

H2O—water

hr—hour

kW—kilowatt electrical

kWh—kilowatt hour

lb—pound

mmBtu—million Btu

MWe—megawatt electrical
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MWh—megawatt hour

NOX—nitrogen oxides

O2—oxygen

ppm—parts per million

scfh—standard cubic feet per hour

SO2—sulfur dioxide

yr—year

§ 97.504 Applicability.

(a) Except as provided in paragraph (b) of this section:

(1) The following units in a State (including Indian country 

located 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.
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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

Ozone Season unit begins to combust fossil fuel or to serve a 

generator with nameplate capacity of more than 25 MWe producing 

electricity for sale, the unit shall become a TR NOX Ozone Season

unit as provided in paragraph (a)(1) of this section on the 

first date on which it both combusts fossil fuel and serves such 

generator.

(b) Any unit in a State (including Indian country located 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), (b)(2)(i), or 

(b)(2)(ii) of this section shall not be a TR NOX Ozone Season

unit:

(1)(i) Any unit:

(A) Qualifying as a cogeneration unit 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; and

(B) Not supplying in 2005 or any calendar year thereafter more 

than one-third of the unit's potential electric output capacity 
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or 219,000 MWh, whichever is greater, to any utility power 

distribution system for sale.

(ii) If a unit qualifies as a cogeneration unit throughout the 

later of 2005 or the 12-month period starting on the date the 

unit first produces electricity and meets the requirements of 

paragraphs (b)(1)(i) of this section for at least one calendar 

year, but subsequently no longer meets such qualification and 

requirements, the unit shall become a TR NOX Ozone Season unit 

starting on the earlier of January 1 after the first calendar 

year during which the unit first no longer qualifies as a 

cogeneration unit or January 1 after the first calendar year 

during which the unit no longer meets the requirements of 

paragraph (b)(1)(i)(B) of this section.

(2)(i) Any unit:

(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; and

(B) With an average Ozone Season 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 Ozone Season fuel consumption of fossil fuel for 
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any 3 consecutive calendar years thereafter of less than 20 

percent (on a Btu basis).

(ii) If a unit qualifies 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 meets the 

requirements of paragraph (b)(2)(i) of this section for at least 

3 consecutive calendar years, but subsequently no longer meets 

such qualification and requirements, the unit shall become a TR 

NOX Ozone Season unit starting on the earlier of January 1 after 

the first calendar year during which the unit first no longer 

qualifies as a solid waste incineration unit or January 1 after 

the first 3 consecutive calendar years after 2005 for which the 

unit has an average Ozone Season fuel consumption of fossil fuel 

of 20 percent or more.

(c) A certifying official of an owner or operator of any unit or 

other equipment may submit a petition (including any supporting 

documents) to the Administrator at any time for a determination 

concerning the applicability, under paragraphs (a) and (b) of 

this section, of the TR NOX Ozone Season Trading Program to the 

unit or other equipment.

(1) Petition content. The petition shall be in writing and 

include the identification of the unit or other equipment and 
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the relevant facts about the unit or other equipment. The 

petition and any other documents provided to the Administrator 

in connection with the petition shall include the following 

certification statement, signed by the certifying official: “I 

am authorized to make this submission on behalf of the owners 

and operators of the unit or other equipment for which the 

submission is made. I certify under penalty of law that I have 

personally examined, and am familiar with, the statements and 

information submitted in this document and all its attachments. 

Based on my inquiry of those individuals with primary 

responsibility for obtaining the information, I certify that the 

statements and information are to the best of my knowledge and 

belief true, accurate, and complete. I am aware that there are 

significant penalties for submitting false statements and 

information or omitting required statements and information, 

including the possibility of fine or imprisonment.”

(2) Response. The Administrator will issue a written response to 

the petition and may request supplemental information determined 

by the Administrator to be relevant to such petition. The 

Administrator's determination concerning the applicability, 

under paragraphs (a) and (b) of this section, of the TR NOX Ozone 

Season Trading Program to the unit or other equipment shall be 

binding on any State or permitting authority unless the 
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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 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 
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includes the unit, records demonstrating that the unit is 

permanently retired. The 5-year period for keeping records may 

be extended for cause, at any time before the end of the period, 

in writing by the Administrator. The owners and operators bear 

the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the 

designated representative of a unit exempt under paragraph (a) 

of this section shall comply with the requirements of the TR NOX

Ozone Season Trading Program concerning all periods for which 

the exemption is not in effect, even if such requirements arise, 

or must be complied with, after the exemption takes effect.

(4) A unit exempt under paragraph (a) of this section shall lose 

its exemption on the first date on which the unit resumes 

operation. Such unit shall be treated, for purposes of applying 

allocation, monitoring, reporting, and recordkeeping 

requirements under this subpart, as a unit that commences 

commercial operation on the first date on which the unit resumes 

operation.

§ 97.506 Standard requirements.

(a) Designated representative requirements. The owners and 

operators shall comply with the requirement to have a designated 
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representative, and may have an alternate designated 

representative, in accordance with §§97.513 through 97.518.

(b) Emissions monitoring, reporting, and recordkeeping 

requirements. (1) The owners and operators, and the designated 

representative, of each TR NOX Ozone Season source and each TR 

NOX Ozone Season unit at the source shall comply with the 

monitoring, reporting, and recordkeeping requirements of 

§§97.530 through 97.535.

(2) The emissions data determined in accordance with §§97.530 

through 97.535 shall be used to calculate allocations of TR NOX

Ozone Season allowances under §§97.511(a)(2) and (b) and 97.512 

and to determine compliance with the TR NOX Ozone Season

emissions limitation and assurance provisions under paragraph 

(c) of this section, provided that, for each monitoring location 

from which mass emissions are reported, the mass emissions 

amount used in calculating such allocations and determining such 

compliance shall be the mass emissions amount for the monitoring 

location determined in accordance with §§97.530 through 97.535 

and rounded to the nearest ton, with any fraction of a ton less 

than 0.50 being deemed to be zero.

(c) NOX emissions requirements. (1) TR NOX Ozone Season

emissions limitation. (i) As of the allowance transfer deadline 
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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 each day of such control period shall constitute a 

separate violation of this subpart and the Clean Air Act.
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(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 

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 (as of the 

allowance transfer deadline 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 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 for such 

control period, by which each common designated representative’s 
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share of such NOX emissions exceeds the respective common 

designated representative’s assurance level; and

(B) Two times the amount by which total NOX emissions from all TR 

NOX Ozone Season units at TR NOX Ozone Season sources in the 

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 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 

one-year 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 during a control period 

exceed the State assurance level or if a common designated 

representative’s share of total NOX emissions from the TR NOX

Ozone Season units at TR NOX Ozone Season sources in a State 
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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.
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(4) Vintage of deducted allowances. A TR NOX Ozone Season

allowance shall not be deducted, for compliance with the 

requirements under paragraphs (c)(1)(i) and (2)(i) through (iii)

of this section, for a control period in a calendar year before 

the year for which the TR NOX Ozone Season allowance was 

allocated.

(5) Allowance Management System requirements. Each TR NOX Ozone 

Season allowance shall be held in, deducted from, or transferred 

into, out of, or between Allowance Management System accounts in 

accordance with this subpart.

(6) Limited authorization. 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 determines is necessary or appropriate to 

implement any provision of the Clean Air Act. 
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(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 
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demonstrate compliance with the requirements of, the TR NOX Ozone 

Season Trading Program.

(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. 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 
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provision of the applicable, approved State implementation plan, 

a federally enforceable permit, or the Clean Air Act.

§ 97.507 Computation of time.

(a) Unless otherwise stated, any time period scheduled, under 

the TR NOX Ozone Season Trading Program, to begin on the 

occurrence of an act or event shall begin on the day the act or 

event occurs. 

(b) Unless otherwise stated, any time period scheduled, under 

the TR NOX Ozone Season Trading Program, to begin before the 

occurrence of an act or event shall be computed so that the 

period ends the day before the act or event occurs.

(c) Unless otherwise stated, if the final day of any time 

period, under the TR NOX Ozone Season Trading Program, 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]
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§ 97.510 State NOX Ozone Season trading budgets, new unit setasides, Indian country new unit set-aside, and variability 

limits.

(a) The State NOX Ozone Season trading budgets, new unit setasides, 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:

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 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 ---
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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 ---

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’ one-year variability limits for the State NOX

Ozone Season trading budgets for the control periods in 2012 and 

thereafter are as follows:
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State

One-year variability limits

for 2012 and 2013

One-year

variability limits

for 2014 and thereafter

Alabama 7,269 7,196

Georgia 6,201 4,054

Illinois 4,787 4,787

Indiana 10,973 10,842

Iowa 3,834 3,750

Kansas 3,071 2,556

Kentucky 8,509 7,724

Maryland 1,663 1,657

Michigan 6,019 5,781

Minnesota 2,957 2,957

Missouri 5,237 4,872

Nebraska 2,644 2,644

New Jersey 727 727

New York 2,631 2,631

North Carolina 5,059 4,155

Ohio 9,270 8,749

Pennsylvania 11,999 11,919

South Carolina 3,250 3,250

Tennessee 3,570 1,934

Texas 13,360 13,360

Virginia 3,324 3,324

West Virginia 5,947 5,458

Wisconsin 3,163 3,040

§ 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 for a unit in such 
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notice does not constitute a determination that the unit is a TR 

NOX Ozone Season unit, and not providing an allocation for 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 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 for each 

TR NOX Ozone Season unit, in accordance with §97.512(a)(1) 

through (8), for the control period in the year of the 
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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 are in accordance with §97.512(a)(1) through (8)

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)(1) through (8) and the reasons for accepting or 
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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 

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. 
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(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 for each TR NOX Ozone Season unit in 

accordance with §97.512(a)(9) and (10) 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.

(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 for each TR NOX

Ozone Season unit, in accordance with §97.512(b)(1) through (8), 

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)(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 are in accordance with §97.512(b)(1) through (8)

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)(1) through (8) 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 
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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 

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 
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(b)(2)(iii) of this section and will calculate the TR NOX Ozone 

Season allowance allocation for each TR NOX Ozone Season unit in 

accordance with §97.512(b)(9) and (10) 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. 

(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 §52.37(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 paragraph (b) of this section 

and §97.512, or under a provision of a SIP revision approved 

under §52.37(b)(3), (4), or (5) of this chapter, where such 

control period and the recipient are covered by the provisions 
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of paragraph (c)(1)(ii) of this section, then the Administrator 

will notify the designated representative 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 under a provision of a SIP revision approved under 

§52.37(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 TR 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 §52.37(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 
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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 §52.37(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. 

(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.
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(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. 

(5) The Administrator will transfer the TR NOX Ozone Season

allowances that are not recorded, or that are deducted, in 

accordance with paragraphs (c)(2) and (3) of this section to, 

for a recipient under paragraph (c)(1)(i) of this section, the 

new unit set-aside for the State from whose NOX Ozone Season 

trading budget the TR NOX Ozone Season allowances were allocated, 

or, for a recipient under paragraph (c)(1)(ii) of this 

paragraph, to the State’s new unit set-aside or Indian country 

new unit set-aside from which the TR NOX Ozone Season allowances 

were allocated, for the control period in the year of such 

transfer.

§ 97.512 TR NOX Ozone Season allowance allocations for new 

units.

(a) For each control period in 2012 and thereafter and for the 

TR NOX Ozone Season units in each State other than those located 
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in Indian county, the Administrator will allocate TR NOX Ozone 

Season allowances to the TR NOX Ozone Season units described in 

paragraph (a)(1) of this section and in accordance with 

paragraphs (a)(2) through (9) of this section:

(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:

(i) TR NOX Ozone Season units that are not allocated an amount 

(whether zero or greater) 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 

(whether zero or greater) 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 

(whether zero or greater) 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
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(iv) TR NOX Ozone Season units under §97.511(c)(1)(ii) whose 

allocation of an amount (whether zero or greater) 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 setaside for the State for each such control period. Each such 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(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;
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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 NOX Ozone 

Season unit operates in the non-Indian country portion of 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 for each TR NOX Ozone Season unit described 

in paragraph (a)(1) 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.

(ii) The Administrator will adjust the allocation amount in 

paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through 

(9) 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.
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(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 setaside 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 

§97.511(b)(1)(i) and (ii), of the amount of TR NOX Ozone Season

allowances allocated under paragraphs (a)(1) through (8) for 

such control period to each TR NOX Ozone Season unit eligible for 

such allocation.
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(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 described in the notice of data 

availability required under §97.511(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 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 
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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.

(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 for 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 paragraph 

(a)(9) 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 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 
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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 setaside 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) and (iv), of the amount of TR NOX Ozone Season

allowances allocated for such control period to each TR NOX Ozone 

Season unit eligible for such allocation.

(b) For each control period in 2012 and thereafter and for the 

TR NOX Ozone Season units located in Indian country in each 

State, the Administrator will allocate TR NOX Ozone Season

allowances to the TR NOX Ozone Season units described in 

paragraph (b)(1) of this section and in accordance with 

paragraphs (b)(2) through (9) of this section:
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(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 

(whether zero or greater) of TR NOX Ozone Season allowances in 

the notice of data availability issued under §97.511(a)(1); or

(ii) TR NOX Ozone Season units under §97.511(c)(1)(ii) whose 

allocation of an amount (whether zero or greater) 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). 

(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 
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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 for each TR NOX Ozone Season unit described 

in paragraph (b)(1) 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 

(9) 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 (b)(4)(i) of this section in 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 
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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

allowances allocated under paragraphs (b)(1) through (8) 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 
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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 described 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 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.
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(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 

for 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 paragraph 

(b)(9) 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:

(i) Allocate 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 §52.37(b)(4) 

or (5), include such unallocated TR NOX Ozone Season allowances 

in the portion of the State TR NOX Ozone Season trading budget 
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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) and (iv), of the amount of TR NOX Ozone Season

allowances allocated for such control period to each TR NOX Ozone 

Season unit eligible for such allocation.

§ 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:
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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 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 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 
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accordance with the certification statement in 

§97.516(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete 

certificate of representation under §97.516, 

(i) The alternate designated representative shall be authorized; 

(ii) Any representation, action, inaction, or submission by the 

alternate designated representative shall be deemed to be a 

representation, action, inaction, or submission by the 

designated representative; and

(iii) The owners and operators of the source and each TR NOX

Ozone Season unit at the source shall be bound by any decision 

or order issued to the alternate designated representative by 

the Administrator regarding the source or any such unit.

(c) Except in this section, §97.502, and §§97.514 through 

97.518, whenever the term “designated representative” (as 

distinguished from theterm “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.
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(a) Except as provided under §97.518 concerning delegation of 

authority to make submissions, each submission under the TR NOX

Ozone Season Trading Program shall be made, signed, and 

certified by the designated representative or alternate 

designated representative for each TR NOX Ozone Season source and 

TR NOX Ozone Season unit for which the submission is made. Each 

such submission shall include the following certification 

statement by the designated representative or alternate 

designated representative: “I am authorized to make this 

submission on behalf of the owners and operators of the source 

or units for which the submission is made. I certify under 

penalty of law that I have personally examined, and am familiar 

with, the statements and information submitted in this document 

and all its attachments. Based on my inquiry of those 

individuals with primary responsibility for obtaining the 

information, I certify that the statements and information are 

to the best of my knowledge and belief true, accurate, and 

complete. I am aware that there are significant penalties for 

submitting false statements and information or omitting required 

statements and information, including the possibility of fine or 

imprisonment.”

(b) The Administrator will accept or act on a submission made 

for a TR NOX Ozone Season source or a TR NOX Ozone Season unit 
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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.

(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 
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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 representative shall submit a revision to the 

certificate of representation under §97.516 amending the list of 

owners and operators to reflect the change.
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(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 was sold or otherwise obtained, and the date on which the 

unit became no longer located at the source. 

§ 97.516 Certificate of representation.
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(a) A complete certificate of representation for a designated 

representative or an alternate designated representative shall 

include the following elements in a format prescribed by the 

Administrator:

(1) Identification of the TR NOX Ozone Season source, and each TR 

NOX Ozone Season unit at the source, for which the certificate of 

representation is submitted, including source name, source 

category and NAICS code (or, in the absence of a NAICS code, an 

equivalent code), State, plant code, county, latitude and 

longitude, unit identification number and type, identification 

number and nameplate capacity (in MWe, rounded to the nearest 

tenth) of each generator served by each such unit, and actual or 

projected date of commencement of commercial operation and 

including 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 
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representative’ or ‘alternate designated representative’, as 

applicable, and of the agreement by which I was selected to each 

owner and operator of the source and of each TR NOX Ozone Season

unit at the source; and TR NOX Ozone Season allowances and 

proceeds of transactions involving TR NOX Ozone Season allowances 

will be deemed to be held or distributed in proportion to each 

holder's legal, equitable, leasehold, or contractual reservation 

or entitlement, except that, if such multiple holders have 

expressly provided for a different distribution of TR NOX Ozone 

Season allowances by contract, TR NOX Ozone Season allowances and 

proceeds of transactions involving TR NOX Ozone Season allowances 

will be deemed to be held or distributed in accordance with the 

contract.”

(5) The signature of the designated representative and any 

alternate designated representative and the dates signed.

(b) Unless otherwise required by the Administrator, documents of 

agreement referred to in the certificate of representation shall 

not be submitted to the Administrator. The Administrator shall 

not be under any obligation to review or evaluate the 

sufficiency of such documents, if submitted.

§ 97.517 Objections concerning designated representative and 

alternate designated representative.
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(a) Once a complete certificate of representation under §97.516 

has been submitted and received, the Administrator will rely on 

the certificate of representation unless and until a superseding 

complete certificate of representation under §97.516 is received 

by the Administrator.

(b) Except as provided in 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.
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(a) A designated representative may delegate, to one or more 

natural persons, his or her authority to make an electronic 

submission to the Administrator provided for or required under 

this subpart.

(b) An alternate designated representative may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(c) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph (a) 

or (b) of this section, the designated representative or 

alternate designated representative, as appropriate, must submit 

to the Administrator a notice of delegation, in a format 

prescribed by the Administrator, that includes the following 

elements:

(1) The name, address, e-mail address, telephone number, and 

facsimile transmission number (if any) of such designated 

representative or alternate designated representative;

(2) The name, address, e-mail address, telephone number, and 

facsimile transmission number (if any) of each such natural 

person (referred to in this section as an “agent”);
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(3) For each such natural person, a list of the type or types of 

electronic submissions under paragraph (a) or (b) of this 

section for which authority is delegated to him or her; and

(4) The following certification statements by such designated 

representative or alternate designated representative:

(i) “I agree that any electronic submission to the Administrator 

that is made by an agent identified in this notice of delegation 

and of a type listed for such agent in this notice of delegation 

and that is made when I am a designated representative or 

alternate designated representative, as appropriate, and before 

this notice of delegation is superseded by another notice of 

delegation under 40 CFR 97.518(d) shall be deemed to be an 

electronic submission by me.”

(ii) “Until this notice of delegation is superseded by another 

notice of delegation under 40 CFR 97.518(d), I agree to maintain 

an e-mail account and to notify the Administrator immediately of 

any change in my e-mail address unless all delegation of 

authority by me under 40 CFR 97.518 is terminated.”.

(d) A notice of delegation submitted under paragraph (c) of this 

section shall be effective, with regard to the designated 

representative or alternate designated representative identified 

in such notice, upon receipt of such notice by the Administrator 
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and until receipt by the Administrator of a superseding notice 

of delegation submitted by such designated representative or 

alternate designated representative, as appropriate. The 

superseding notice of delegation may replace any previously 

identified agent, add a new agent, or eliminate entirely any 

delegation of authority.

(e) Any electronic submission covered by the certification in 

paragraph (c)(4)(i) of this section and made in accordance with 

a notice of delegation effective under paragraph (d) of this 

section shall be deemed to be an electronic submission by the 

designated representative or alternate designated representative 

submitting such notice of delegation.

§ 97.519 [Reserved]

§ 97.520 Establishment of 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 
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representative and the alternate authorized account 

representative respectively of the compliance account.

(b) Assurance accounts. As provided in §97.525(b)(3), the 

Administrator will establish assurance accounts for the owners 

and operators and States specified in the notice required under 

§97.525(b)(2)(iii)(B). 

(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 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 
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authorizing the alternate authorized account representative to 

act in lieu of the authorized account representative.

(ii) A complete application for a general account shall include 

the following elements in a format prescribed by the 

Administrator:

(A) Name, mailing address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of the 

authorized account representative and any alternate authorized 

account representative;

(B) An identifying name for the general account;

(C) A list of all persons subject to a binding agreement for the 

authorized account representative and any alternate authorized 

account representative to represent their ownership interest 

with respect to the TR NOX Ozone Season allowances held in the 

general account;

(D) The following certification statement by the authorized 

account representative and any alternate authorized account 

representative: “I certify that I was selected as the authorized 

account representative or the alternate authorized account 

representative, as applicable, by an agreement that is binding 

on all persons who have an ownership interest with respect to TR 
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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 general account for the person or 

persons for whom the application is submitted, and upon and 

after such receipt by the Administrator:
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(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 

submission concerning the general account shall be made, signed, 

and certified by the authorized account representative or any 
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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 
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persons with an ownership interest with respect to the TR NOX

Ozone Season allowances in the general account.

(iii)(A) In the event a person having an ownership interest with 

respect to TR NOX Ozone Season allowances in the general account 

is not included in the list of such persons in the application 

for a general account, such person shall be deemed to be subject 

to and bound by the application for a general account, the 

representation, actions, inactions, and submissions of the 

authorized account representative and any alternate authorized 

account representative of the account, and the decisions and 

orders of the Administrator, as if the person were included in 

such list.

(B) Within 30 days after any change in the persons having an 

ownership interest with respect to NOX Ozone Season allowances in 

the general account, including the addition 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 
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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 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 
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disputes concerning the proceeds of TR NOX Ozone Season allowance 

transfers.

(5) Delegation by authorized account representative and 

alternate authorized account representative. (i) An authorized 

account representative of a general account may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(ii) An alternate authorized account representative of a general 

account may delegate, to one or more natural persons, his or her 

authority to make an electronic submission to the Administrator 

provided for or required under this subpart.

(iii) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph 

(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 
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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 97.520(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 
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agree to maintain an e-mail account and to notify the 

Administrator immediately of any change in my e-mail address 

unless all delegation of authority by me under 40 CFR 

97.520(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)(i) The authorized account representative or alternate 

authorized account representative of a general account may 
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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 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.
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(d) 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.

(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 
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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 §52.37(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.

(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 
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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 for the TR NOX Ozone Season units at the 

source in accordance with §97.511(a), or with a SIP revision

approved under §52.37(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 for the TR NOX Ozone Season units at the 

source in accordance with §97.511(a), or with a SIP revision

approved under §52.37(b)(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

Ozone Season source's compliance account the TR NOX Ozone Season

allowances allocated for the TR NOX Ozone Season units at the 

source in accordance with §97.511(a), or with a SIP revision

approved under §52.37(b)(4) or (5) of this chapter, for the 

control period in 2018 and 2019.
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(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 

for the TR NOX Ozone Season units at the source in accordance 

with §97.511(a), or with a SIP revision approved under 

§52.37(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 

for the TR NOX Ozone Season units at the source in accordance 

with §97.512(a), or with a SIP revision approved under 

§52.37(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 

for the TR NOX Ozone Season units at the source in accordance 

with §97.512(b) for the control period in the year of the 

applicable recordation deadline under this paragraph.
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(i) By the date on which any allocation, other than an 

allocation described in paragraphs (a) through (h) of this 

section, of TR NOX Ozone Season allowances to a recipient is made 

by or submitted to the Administrator in accordance with §97.511 

or §97.512 or with a SIP revision approved under §52.37(b)(4) or 

(5) of this chapter, the Administrator will record such 

allocation in the appropriate Allowance Management System 

account. 

(j) To the extent a SIP revision approved under §52.37(b)(4) or 

(5) of this chapter provides for one or more auctions, in lieu 

of allocation, of TR NOX Ozone Season allowances for a control 

period in a given year, the Administrator will record in the 

appropriate Allowance Management System account under such SIP 

revision the amount of TR NOX Ozone Season allowances purchased 

at such auctions by the deadline, specified in paragraphs (a) 

through (h) of this section, for recordation of an allocation 

for the control period in such year. 

(k) When recording the allocation or auction of TR NOX Ozone 

Season allowances for a TR NOX Ozone Season unit 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.
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§ 97.522 Submission of TR NOX Ozone Season allowance transfers.

(a) An authorized account representative seeking recordation of 

a TR NOX Ozone Season allowance transfer shall submit the 

transfer to the Administrator. 

(b) A TR NOX Ozone Season allowance transfer shall be correctly 

submitted if: 

(1) The transfer includes the following elements, in a format 

prescribed by the Administrator:

(i) The account numbers established by the Administrator for 

both the transferor and transferee accounts;

(ii) The serial number of each TR NOX Ozone Season allowance that 

is in the transferor account and is to be transferred; and

(iii) The name and signature of the authorized account 

representative of the transferor account and the date signed; 

and

(2) When the Administrator attempts to record the transfer, the 

transferor account includes each TR NOX Ozone Season allowance 

identified by serial number in the transfer. 

§ 97.523 Recordation of TR NOX Ozone Season allowance transfers.
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(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.

(d) Within 5 business days of recordation of a TR NOX Ozone 

Season allowance transfer under paragraphs (a) and (b) of the 
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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 
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shall be submitted to the Administrator by the allowance 

transfer deadline for such control period and include, in a 

format prescribed by the Administrator, the identification of 

the TR NOX Ozone Season source and the appropriate serial 

numbers.

(2) First-in, first-out. The Administrator will deduct TR NOX

Ozone Season allowances under paragraph (b) or (d) of this 

section from the source's compliance account in accordance with 

a complete request under paragraph (c)(1) of this section or, in 

the absence of such request or in the case of identification of 

an insufficient amount of TR NOX Ozone Season allowances in such 

request, on a first-in, first-out 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
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source has excess emissions, the Administrator will deduct from 

the source's compliance account an amount of TR NOX Ozone Season

allowances, allocated for the control period in the immediately 

following year, equal to two times the number of tons of the 

source's excess emissions.

(e) Recordation of deductions. The Administrator will record in 

the appropriate compliance account all deductions from such an 

account under paragraphs (b) and (d) of this section.

§ 97.525 Compliance with TR NOX Ozone Season assurance 

provisions.

(a) Availability for deduction. TR NOX Ozone Season allowances 

are available to be deducted for compliance with the TR NOX Ozone 

Season assurance provisions for a control period in a given year 

by the owners and operators of a group of one or more TR NOX

Ozone Season sources and units in a State 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 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 under paragraph 
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(b)(3) of this section, as of the deadline established in 

paragraph (b)(5) of this section. 

(b) Deductions for compliance. The Administrator will deduct TR 

NOX Ozone Season allowances available under paragraph (a) of this 

section for compliance with the TR NOX Ozone Season assurance 

provisions for a State for a control period in a given year in 

accordance with the following procedures:

(1) By June 1, 2013 and June 1 of each year thereafter, the 

Administrator will:

(i) Calculate, separately for each State, the total NOX emissions 

from all TR NOX Ozone Season units at TR NOX Ozone Season sources

in the State during the control period in the year before the 

year of this calculation deadline and the amount, if any, by 

which such total 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 identified in such 
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notice as having TR NOX Ozone Season units with total NOX

emissions exceeding the State 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 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 each common designated representative (authorized as of the 

allowance transfer deadline for such control period) for a group 

of one or more TR NOX Ozone Season sources and units in the State 

and for such control period, 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, 

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 
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accordance 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 
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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 accepting or 

rejecting any objections submitted in accordance with paragraph 

(b)(2)(iii)(A) of this section.

(3) For any State identified 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 identified, 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 having a common 

designated representative (as of the allowance transfer deadline 

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 
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the appropriate TR NOX Ozone Season sources, TR NOX Ozone Season

units, and 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 to hold with regard to such 

sources, units and 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 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 
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and operators are required to hold with regard to such sources, 

units, and States as calculated by the Administrator and 

referenced in the notice required in paragraph (b)(2)(iii)(B) of 

this section.

(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 
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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 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 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 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.
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(iii) If the revised data are used to recalculate, in accordance 

with paragraphs (b)(6)(i) and (b)(6)(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 involved—

(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 under paragraph (b)(3) of this 

section. The owners’ and operaters’ 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. 
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(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 under paragraph (b)(3) of 

this section, a total amount of TR NOX Ozone Season allowances 

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, or recorded under paragraph 

(b)(6)(iii)(B) 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 such control period or a control period in a prior 

year. 
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§ 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.

§ 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.
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(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 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 
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that is monitored under §75.72(b)(2)(ii) of this chapter shall 

comply with the same monitoring, recordkeeping, and reporting 

requirements as a TR NOX Ozone Season unit.

(a) Requirements for installation, certification, and data accounting.

The owner or operator of each TR NOX Ozone Season unit shall:

(1) Install all monitoring systems required under this subpart for 

monitoring NOX mass emissions and individual unit heat input (including 

all systems required to monitor NOX emission rate, NOX concentration, 

stack gas moisture content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as applicable, in accordance with 

§§75.71 and 75.72 of this chapter);

(2) Successfully complete all certification tests required under 

§97.531 and meet all other requirements of this subpart and part 75 of 

this chapter applicable to the monitoring systems under paragraph 

(a)(1) of this section; and

(3) Record, report, and quality-assure the data from the monitoring 

systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) of this 

section, the owner or operator shall meet the monitoring system 

certification and other requirements of paragraphs (a)(1) and (2) of 

this section on or before the following dates. The owner or operator 
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shall record, report, and quality-assure the data from the monitoring 

systems under paragraph (a)(1) of this section on and after the 

following dates.

(1) For the owner or operator of a TR NOX Ozone Season unit that 

commences commercial operation before July 1, 2011, by May 1, 2012.

(2) For the owner or operator of a TR NOX Ozone Season unit that 

commences commercial operation on or after July 1, 2011 and that 

reports on an annual basis under §97.534(d), by the later of the 

following dates:

(i) 180 calendar days after the date on which the unit commences 

commercial operation; or

(ii) May 1, 2012.

(3) For the owner or operator of a TR NOX Ozone Season unit that 

commences commercial operation on or after July 1, 2011 and that 

reports on a control period basis under §97.534(d)(2)(ii), by the 

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 
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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) 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 §97.530 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

(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 
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system under paragraph (a)(1) of this section shall, for each 

such monitoring system, determine, record, and report maximum 

potential (or, as appropriate, minimum potential) values for NOX

concentration, NOX emission rate, stack gas flow rate, stack gas 

moisture content, fuel flow rate, and any other parameters 

required to determine NOX mass emissions and heat input in 

accordance with § 75.31(b)(2) or (c)(3) of this chapter, section 

2.4 of appendix D to part 75 of this chapter, or section 2.5 of 

appendix E to part 75 of this chapter, as applicable.

(d) Prohibitions. (1) No owner or operator of a TR NOX Ozone 

Season unit shall use any alternative monitoring system, 

alternative reference method, or any other alternative to any 

requirement of this subpart without having obtained prior 

written approval in accordance with §97.535.

(2) No owner or operator of a TR NOX Ozone Season unit shall 

operate the unit so as to discharge, or allow to be discharged, 

NOX emissions to the atmosphere without accounting for all such 

emissions in accordance with the applicable provisions of this 

subpart and part 75 of this chapter.

(3) No owner or operator of a TR NOX Ozone Season unit shall

disrupt the continuous emission monitoring system, any portion 
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thereof, or any other approved emission monitoring method, and 

thereby avoid monitoring and recording NOX mass emissions 

discharged into the atmosphere or heat input, except for periods 

of recertification or periods when calibration, quality 

assurance testing, or maintenance is performed in accordance 

with the applicable provisions of this subpart and part 75 of 

this chapter.

(4) No owner or operator of a TR NOX Ozone Season unit shall 

retire or permanently discontinue use of the continuous emission 

monitoring system, any component thereof, or any other approved 

monitoring system under this subpart, except under any one of 

the following circumstances:

(i) During the period that the unit is covered by an exemption 

under §97.505 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit 

with another certified monitoring system approved, in accordance 

with the applicable provisions of this subpart and part 75 of 

this chapter, by the Administrator for use at that unit that 

provides emission data for the same pollutant or parameter as 

the retired or discontinued monitoring system; or
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(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) 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 
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of this chapter shall comply with the procedures in paragraph 

(e) or (f) of this section respectively.

(1) Requirements for initial certification. The owner or 

operator shall ensure that each continuous monitoring system 

under § 97.530(a)(1) (including the automated data acquisition 

and handling system) successfully completes all of the initial 

certification testing required under §75.20 of this chapter by 

the applicable deadline in § 97.530(b). In addition, whenever 

the owner or operator installs a monitoring system to meet the 

requirements of this subpart in a location where no such 

monitoring system was previously installed, initial 

certification in accordance with §75.20 of this chapter is 

required.

(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. 
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Furthermore, whenever the owner or operator makes a replacement, 

modification, or change to the flue gas handling system or the 

unit's operation that may significantly change the stack flow or 

concentration profile, the owner or operator shall recertify 

each continuous emission monitoring system whose accuracy is 

potentially affected by the change, in accordance with §75.20(b) 

of this chapter. Examples of changes to a continuous emission 

monitoring system that require recertification include: 

replacement of the analyzer, complete replacement of an existing 

continuous emission monitoring system, or change in location or 

orientation of the sampling probe or site. Any fuel flowmeter 

systems, and any excepted NOX monitoring system under appendix E 

to part 75 of this chapter, under §97.530(a)(1) are subject to 

the recertification requirements in §75.20(g)(6) of this 

chapter.

(3) Approval process for initial certification and 

recertification. For initial certification of a continuous 

monitoring system under §97.530(a)(1), paragraphs (d)(3)(i) 

through (v) of this section apply. For recertifications of such 

monitoring systems, paragraphs (d)(3)(i) through (iv) of this 

section and the procedures in §§75.20(b)(5) and (g)(7) of this 

chapter (in lieu of the procedures in paragraph (d)(3)(v) of 

this section) apply, provided that in applying paragraphs
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(d)(3)(i) through (iv) of this section, the words 

“certification” and “initial certification” are replaced by the 

word “recertification” and the word “certified” is replaced by 

with the word “recertified”. 

(i) Notification of certification. The designated representative 

shall submit to the appropriate EPA Regional Office and the 

Administrator written notice of the dates of certification 

testing, in accordance with §97.533.

(ii) Certification application. The designated representative 

shall submit to the Administrator a certification application 

for each monitoring system. A complete certification application 

shall include the information specified in §75.63 of this 

chapter.

(iii) Provisional certification date. The provisional 

certification date for a monitoring system shall be determined 

in accordance with §75.20(a)(3) of this chapter. A provisionally 

certified monitoring system may be used under the TR NOX Ozone 

Season Trading Program for a period not to exceed 120 days after 

receipt by the Administrator of the complete certification 

application for the monitoring system under paragraph (d)(3)(ii) 

of this section. Data measured and recorded by the provisionally 
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certified monitoring system, in accordance with the requirements 

of part 75 of this chapter, will be considered valid qualityassured data (retroactive to the date and time of provisional 

certification), provided that the Administrator does not 

invalidate the provisional certification by issuing a notice of 

disapproval within 120 days of the date of receipt of the 

complete certification application by the Administrator.

(iv) Certification application approval process. The 

Administrator will issue a written notice of approval or 

disapproval of the certification application to the owner or 

operator within 120 days of receipt of the complete 

certification application under paragraph (d)(3)(ii) of this 

section. In the event the Administrator does not issue such a 

notice within such 120-day period, each monitoring system that 

meets the applicable performance requirements of part 75 of this 

chapter and is included in the certification application will be 

deemed certified for use under the TR NOX Ozone Season Trading 

Program.

(A) Approval notice. If the certification application is 

complete and shows that each monitoring system meets the 

applicable performance requirements of part 75 of this chapter, 

then the Administrator will issue a written notice of approval 
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of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification 

application is not complete, then the Administrator will issue a 

written notice of incompleteness that sets a reasonable date by 

which the designated representative must submit the additional 

information required to complete the certification application. 

If the designated representative does not comply with the notice 

of incompleteness by the specified date, then the Administrator 

may issue a notice of disapproval under paragraph (d)(3)(iv)(C) 

of this section. The 120-day review period specified in 

paragraph (d)(3) of this section shall not begin before receipt 

of a complete certification application.

(C) Disapproval notice. If the certification application shows 

that any monitoring system does not meet the performance 

requirements of part 75 of this chapter or if the certification 

application is incomplete and the requirement for disapproval 

under paragraph (d)(3)(iv)(B) of this section is met, then the 

Administrator will issue a written notice of disapproval of the 

certification application. Upon issuance of such notice of 

disapproval, the provisional certification is invalidated by the 

Administrator and the data measured and recorded by each 

uncertified monitoring system shall not be considered valid 
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quality-assured data beginning with the date and hour of 

provisional certification (as defined under § 75.20(a)(3) of 

this chapter). 

(D) Audit decertification. The Administrator may issue a notice 

of disapproval of the certification status of a monitor in 

accordance with § 97.532(b).

(v) Procedures for loss of certification. If the Administrator 

issues a notice of disapproval of a certification application 

under paragraph (d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under paragraph 

(d)(3)(iv)(D) of this section, then:

(A) The owner or operator shall substitute the following values, 

for each disapproved monitoring system, for each hour of unit 

operation during the period of invalid data specified under 

§75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter 

and continuing until the applicable date and hour specified 

under §75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) 

system, the maximum potential NOX emission rate, as defined in 

§72.2 of this chapter.
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(2) For a disapproved NOX pollutant concentration monitor and 

disapproved flow monitor, respectively, the maximum potential 

concentration of NOX and the maximum potential flow rate, as 

defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 

of this chapter.

(3) For a disapproved moisture monitoring system and disapproved 

diluent gas monitoring system, respectively, the minimum 

potential moisture percentage and either the maximum potential 

CO2 concentration or the minimum potential O2 concentration (as 

applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 

of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum 

potential fuel flow rate, as defined in section 2.4.2.1 of 

appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under 

appendix E to part 75 of this chapter, the fuel-specific maximum 

potential NOX emission rate, as defined in §72.2 of this chapter.

(B) The designated representative shall submit a notification of 

certification retest dates and a new certification application 
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in accordance with paragraphs (d)(3)(i) and (ii) of this 

section.

(C) The owner or operator shall repeat all certification tests 

or other requirements that were failed by the monitoring system, 

as indicated in the Administrator's notice of disapproval, no 

later than 30 unit operating days after the date of issuance of 

the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low 

mass emissions (LME) excepted methodology under §75.19 of this 

chapter shall meet the applicable certification and 

recertification requirements in §§75.19(a)(2) and 75.20(h) of 

this chapter. If the owner or operator of such a unit elects to 

certify a fuel flowmeter system for heat input determination, 

the owner or operator shall also meet the certification and 

recertification requirements in §75.20(g) of this chapter.

(f) The designated representative of each unit for which the 

owner or operator intends to use an alternative monitoring 

system approved by the Administrator under subpart E of part 75 

of this chapter shall comply with the applicable notification 

and application procedures of §75.20(f) of this chapter.
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§ 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. 
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The data measured and recorded by the monitoring system shall 

not be considered valid quality-assured data from the date of 

issuance of the notification of the revoked certification status 

until the date and time that the owner or operator completes 

subsequently approved initial certification or recertification 

tests for the monitoring system. The owner or operator shall 

follow the applicable initial certification or recertification 

procedures in §97.531 for each disapproved monitoring system.

§ 97.533 Notifications concerning monitoring.

The designated representative of a TR NOX Ozone Season unit shall 

submit written notice to the Administrator in accordance with 

§75.61 of this chapter.

§ 97.534 Recordkeeping and reporting.

(a) General provisions. The designated representative shall 

comply with all recordkeeping and reporting requirements in this 

section, the applicable recordkeeping and reporting requirements 

under §75.73 of this chapter, and the requirements of 

§97.514(a).

(b) Monitoring plans. The owner or operator of a TR NOX Ozone 

Season unit shall comply with requirements of §75.73 (c) and (e) 

of this chapter. 
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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;
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(ii) For a unit that commences commercial operation on or after 

July 1, 2011, the calendar quarter corresponding to the earlier 

of the date of provisional certification or the applicable 

deadline for initial certification under §97.530(b), unless that 

quarter is the third or fourth quarter of 2011 or the first 

quarter of 2012, in which case reporting shall commence in the 

quarter covering May 1, 2012 through June 30, 2012;

(2) If the TR NOX Ozone Season unit is not subject to the Acid 

Rain Program or a TR NOX Annual emissions limitation, then the 

designated representative shall either:

(i) Meet the requirements of subpart H of part 75 (concerning 

monitoring of NOX mass emissions) for such unit for the entire 

year and report the NOX mass emissions data and heat input data 

for such unit in accordance with paragraph (d)(1) of this 

section; or

(ii) Meet the requirements of subpart H of part 75 for the 

control period (including the requirements in §75.74(c) of this 

chapter) and report NOX mass emissions data and heat input data 

(including the data described in §75.74(c)(6) of this chapter) 

for such unit only for the control period of each year and 

report, in an electronic quarterly report in a format prescribed 
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by the Administrator, for each calendar quarter beginning with:

(A) For a unit that commences commercial operation before July 

1, 2011, the calendar quarter covering May 1, 2012 through June 

30, 2012;

(B) For a unit that commences commercial operation on or after 

July 1, 2011, the calendar quarter corresponding to the earlier 

of the date of provisional certification or the applicable 

deadline for initial certification under §97.530(b), unless that 

date is not during a control period, in which case reporting 

shall commence in the quarter that includes May 1 through June 

30 of the first control period after such date;

(3) 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 1 Trading Program, quarterly 
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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.

(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 
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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.

(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 
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§75.34(a)(1) of this chapter, the add-on emission controls were 

operating within the range of parameters listed in the quality 

assurance/quality control program under appendix B to part 75 of 

this chapter and the substitute data values do not 

systematically underestimate NOX emissions; and

(3) For a unit that is reporting on a control period basis under 

paragraph (d)(2)(ii) of this section, the NOX emission rate and 

NOX concentration values substituted for missing data under 

subpart D of part 75 of this chapter are calculated using only 

values from a control period and do not systematically 

underestimate NOX emissions.

§ 97.535 Petitions for alternatives to monitoring, 

recordkeeping, or reporting requirements.

(a) The designated representative of a TR NOX Ozone Season unit 

may submit a petition under §75.66 of this chapter to the 

Administrator, requesting approval to apply an alternative to 

any requirement of §§97.530 through 97.534 or paragraph (5)(i) 

or (ii) of the definition of “owner’s share” in §97.502. 

(b) A petition submitted under paragraph (a) of this section 

shall include sufficient information for the evaluation of the 

petition, including, at a minimum, the following information:
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(i) Identification of each unit and source covered by the 

petition;

(ii) A detailed explanation of why the proposed alternative is 

being suggested in lieu of the requirement;

(iii) A description and diagram of any equipment and procedures 

used in the proposed alternative;

(iv) A demonstration that the proposed alternative is consistent 

with the purposes of the requirement for which the alternative 

is proposed and with the purposes of this subpart and part 75 of 

this chapter and that any adverse effect of approving the 

alternative will be de minimis; and

(v) Any other relevant information that the Administrator may 

require. 

(c) Use of an alternative to any requirement referenced in 

paragraph (a) of this section is in accordance with this subpart 

only to the extent that the petition is approved in writing by 

the Administrator and that such use is in accordance with such 

approval.
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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 for 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.
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97.626 Banking.

97.627 Account error.

97.628 Administrator’s action on submissions.

97.629 [RESERVED]

97.630 General monitoring, recordkeeping, and reporting 

requirements.

97.631 Initial monitoring system certification and 

recertification procedures.

97.632 Monitoring system out-of-control periods.

97.633 Notifications concerning monitoring.

97.634 Recordkeeping and reporting.

97.635 Petitions for alternatives to monitoring, recordkeeping, 

or reporting requirements.

Subpart DDDDD—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 
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Act and §52.38 of this chapter, as a means of mitigating 

interstate transport of fine particulates and nitrogen oxides.

§ 97.602 Definitions.

The terms used in this subpart shall have the meanings set forth 

in this section as follows:

Acid Rain Program means a 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) 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 §52.38(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:
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(1) A TR SO2 Group 1 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 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, with regard to 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 
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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.

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, with regard to 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 
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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, in which are held TR SO2

Group 1 allowances available for 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, with regard to a 

general account, the natural person who is authorized, in 

accordance with this subpart, to transfer and otherwise dispose 

of TR SO2 Group 1 allowances held in the general account and, 

with regard to a TR SO2 Group 1 source’s compliance account, the

designated representative of the source.

Automated data acquisition and handling system or DAHS means the 

component of the continuous emission monitoring system, or other 

emissions monitoring system approved for use under this subpart, 

designed to interpret and convert individual output signals from 

pollutant concentration monitors, flow monitors, diluent gas 
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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 pressuretreated, chemically-treated, or painted wood products), and 

landscape or right-of-way tree trimmings.
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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 

vice-president or the corporation in charge of a principal 

business function or any other person who performs similar 

policy- or decision-making functions for the corporation;

(2) For a partnership or sole proprietorship, a general partner 

or the proprietor respectively; or

(3) For a local government entity or State, federal, or other 

public agency, a principal executive officer or ranking elected 

official.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq. 
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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—

(1) Operating as part of a cogeneration system; and

(2) Producing on an annual average basis during the later of 

2005 or the 12-month period starting on the date that the unit 

first produces electricity and during each calendar year after 

the later of 2005 or the calendar year in which the unit first 

produces electricity—

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less than 5 percent of total 

energy output; and
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(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

(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 
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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 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 
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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) 
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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 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 a designated 

representative where 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.

Common designated representative’s assurance level means, with 

regard to a specific common designated representative and a 

State and control period in a given year for which the State 

assurance level is exceeded as described in §97.606(c)(2)(iii), 
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the common designated representative’s share of the State SO2

Group 1 trading budget with the one-year variability limit for 

the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative:

(1) With regard to a total amount of SO2 emissions from all TR 

SO2 Group 1 units in a State during a control period in a given 

year, the total tonnage of SO2 emissions during such control 

period from a group of one or more TR SO2 Group 1 units located 

in the State and having the common designated representative as 

of the allowance transfer deadline for such control period; 

(2) With regard to a State SO2 Group 1 trading budget for a 

control period in a given year, 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 

having the common designated representative as of the allowance 

transfer deadline 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 to the Administrator for 

recordation in the compliance accounts for such TR SO2 Group 1
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units in accordance with the TR SO2 Group 1 allowance auction 

provisions in a SIP revision approved by the Administrator under 

§52.38(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 

one-year 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, a control period in a given year, 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 0.87 (if the unit is 

a boiler combusting any amount of coal or coal-derived fuel 

during such control period), 0.14 (if the unit is a simple 

combustion turbine during such control period), 0.70 (if the 

unit is a combined cycle turbine during such control period), 

0.46 (if the unit is a boiler combusting only fuel oil or 

natural gas during such control period), or 0.71 (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. 
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Common stack means a single flue through which emissions from 2 

or more units are exhausted.

Compliance account means an Allowance Management System account, 

established by the Administrator for a TR SO2 Group 1 source 

under this subpart, in which any TR SO2 Group 1 allowance 

allocations for the TR SO2 Group 1 units at the source are 

recorded and in which are held any TR SO2 Group 1 allowances 

available for use for a control period in 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 
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and providing a permanent, continuous record of stack gas 

volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A SO2 monitoring system, consisting of a SO2 pollutant 

concentration monitor and an automated data acquisition and 

handling system and providing a permanent, continuous record of 

SO2 emissions, in parts per million (ppm);

(3) A moisture monitoring system, as defined in §75.11(b)(2) of 

this chapter and providing a permanent, continuous record of the 

stack gas moisture content, in percent H2O;

(4) A CO2 monitoring system, consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor plus suitable 

mathematical equations from which the CO2 concentration is 

derived) and an automated data acquisition and handling system 

and providing a permanent, continuous record of CO2 emissions, in 

percent CO2; and

(5) An O2 monitoring system, consisting of an O2 concentration 

monitor and an automated data acquisition and handling system 

and providing a permanent, continuous record of O2, in percent 

O2.
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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, with regard to a TR SO2 Group 1

source and each TR SO2 Group 1 unit at the source, the natural 

person who is authorized by the owners and operators of the 

source and all such units at the source, in accordance with this 

subpart, to represent and legally bind each owner and operator 

in matters pertaining to the TR SO2 Group 1 Trading Program. If 

the TR SO2 Group 1 source is also subject to the Acid Rain

Program, TR NOX Annual Trading Program, or TR NOX Ozone Season 

Trading Program, then this natural person shall be the same 

natural person as the designated representative, as defined in 

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 
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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 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.

Fuel oil means “fuel oil” as defined in §72.2 of this chapter.

General account means an Allowance Management System account, 

established under this subpart, that is not a compliance account 

or an assurance account.
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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.

Heat input rate means, for a unit, the amount of heat input (in 

mmBtu) divided by unit operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input attributed to the fuel 

(in mmBtu) divided by the unit operating time (in hr) during 

which the unit combusts the fuel.

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.
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Indian country means, as defined in 18 U.S.C. 1151:

(1) All land within the limits of any Indian reservation under 

the jurisdiction of the United States Government, 

notwithstanding the issuance of any patent, and, including 

rights-of-way running through the reservation;

(2) All dependent Indian communities within the borders of the 

United States whether within the original or subsequently 

acquired territory thereof, and whether within or without the 

limits of a state; and 

(3) All Indian allotments, the Indian titles to which have not 

been extinguished, including rights-of-way running through the 

same.

Life-of-the-unit, firm power contractual arrangement means a 

unit participation power sales agreement under which a utility 

or industrial customer reserves, or is entitled to receive, a 

specified amount or percentage of nameplate capacity and 

associated energy generated by any specified unit and pays its 

proportional amount of such unit's total costs, pursuant to a 

contract:

(1) For the life of the unit;
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(2) For a cumulative term of no less than 30 years, including 

contracts that permit an election for early termination; or

(3) For a period no less than 25 years or 70 percent of the 

economic useful life of the unit determined as of the time the 

unit is built, with option rights to purchase or release some 

portion of the nameplate capacity and associated energy 

generated by the unit at the end of the period.

Maximum design heat input means, 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 
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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 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, with regard to 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.
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Owner means, with regard to a TR SO2 Group 1 source or a TR SO2

Group 1 unit at a source respectively, any of the following 

persons:

(1) Any holder of any portion of the legal or equitable title in 

a TR SO2 Group 1 unit at the source or the TR SO2 Group 1 unit;

(2) Any holder of a leasehold interest in a TR SO2 Group 1 unit 

at the source or the TR SO2 Group 1 unit, provided that, unless 

expressly provided for in a leasehold agreement, “owner” shall 

not include a passive lessor, or a person who has an equitable 

interest through such lessor, whose rental payments are not 

based (either directly or indirectly) on the revenues or income 

from such TR SO2 Group 1 unit; and

(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.
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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.

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 
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unit (the replacement unit) to be used instead of the demolished 

or retired unit (the replaced unit).

Sequential use of energy means:

(1) For a topping-cycle unit, the use of reject heat from 

electricity production in a useful thermal energy application or 

process; or

(2) For a bottoming-cycle unit, the use of reject heat from 

useful thermal energy application or process in electricity 

production.

Serial number means, for a TR SO2 Group 1 allowance, the unique 

identification number assigned to each TR SO2 Group 1 allowance 

by the Administrator.

Solid waste incineration unit means a stationary, fossil-fuelfired 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 
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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 §52.38(a),(b), (d), (e), and (f)

of this chapter and, when used to refer to a geographic area, 

includes Indian country located within the borders of such 

State.

Submit or serve means to send or transmit a document, 

information, or correspondence to the person specified in 

accordance with the applicable regulation:

(1) In person;

(2) By United States Postal Service; or

(3) By other means of dispatch or transmission and delivery;

(4) Provided that compliance with any “submission” or “service” 

deadline shall be determined by the date of dispatch, 

transmission, or mailing and not the date of receipt.

Topping-cycle unit means a unit in which the energy input to the 

unit is first used to produce useful power, including 

electricity, where at least some of the reject heat from the 
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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 §52.37(a) of this 

chapter (including such a program that is revised in a SIP 

revision approved by the Administrator under §52.37(a)(3) or (4) 
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of this chapter) or with a SIP revision approved by the 

Administrator under §52.37(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 §52.37(b) of this 

chapter (including such a program that is revised by a State in 

a SIP revision approved by the Administrator under §52.37(b)(3) 

or (4) of this chapter) or with a SIP revision approved by the 

Administrator under §52.37(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 §52.38(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., 
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in order to account for compliance with the TR SO2 Group 1

emissions limitation or assurance provisions. 

TR SO2 Group 1 allowances held or hold TR SO2 Group 1 allowances

means the TR SO2 Group 1 allowances treated as included in an 

Allowance Management System account as of a specified point in 

time because at that time they:

(1) Have been recorded by the Administrator in the account or 

transferred into the account by a correctly submitted, but not 

yet recorded, TR SO2 Group 1 allowance transfer in accordance 

with this subpart; and

(2) Have not been transferred out of the account by a correctly 

submitted, but not yet recorded, TR SO2 Group 1 allowance 

transfer in accordance with this subpart.

TR SO2 Group 1 emissions limitation means, for a TR SO2 Group 1

source, the tonnage of SO2 emissions authorized in a control 

period by the TR SO2 Group 1 allowances available for deduction 

for the source under §97.624(a) for such control period.

TR SO2 Group 1 source means a source that includes one or more TR 

SO2 Group 1 units.

TR SO2 Group 1 Trading Program means a multi-state SO2 air 

pollution control and emission reduction program established in 
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accordance with this subpart and §52.38(a)and (b) of this 

chapter (including such a program that is revised by a State in 

a SIP revision approved by the Administrator under §52.38(d) or 

(e) of this chapter) or in a SIP revision approved by the 

Administrator under §52.38(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, 

fossil-fuel-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.
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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).

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:
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Btu—British thermal unit

CO2—carbon dioxide

H2O—water

hr—hour

kW—kilowatt electrical

kWh—kilowatt hour

lb—pound

mmBtu—million Btu

MWe—megawatt electrical

MWh—megawatt hour

NOX—nitrogen oxides

O2—oxygen

ppm—parts per million

scfh—standard cubic feet per hour

SO2—sulfur dioxide

yr—year
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§ 97.604 Applicability.

(a) Except as provided in paragraph (b) of this section:

(1) The following units in a State (including Indian country 

located 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, 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 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 (including Indian country located 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 
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requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or 

(b)(2)(ii) of this section shall not be a TR SO2 Group 1 unit:

(1)(i) Any unit:

(A) Qualifying as a cogeneration unit 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; 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 a unit qualifies as a cogeneration unit throughout the 

later of 2005 or the 12-month period starting on the date the 

unit first produces electricity and meets the requirements of 

paragraphs (b)(1)(i) of this section for at least one calendar 

year, but subsequently no longer meets such qualification and 

requirements, the unit shall become a TR SO2 Group 1 unit 

starting on the earlier of January 1 after the first calendar 

year during which the unit first no longer qualifies as a 

cogeneration unit or January 1 after the first calendar year 

during which the unit no longer meets the requirements of 

paragraph (b)(1)(i)(B) of this section.
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(2)(i) Any unit:

(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; 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 a unit qualifies 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 meets the 

requirements of paragraph (b)(2)(i) of this section for at least 

3 consecutive calendar years, but subsequently no longer meets 

such qualification and requirements, the unit shall become a TR 

SO2 Group 1 unit starting on the earlier of January 1 after the 

first calendar year during which the unit first no longer 

qualifies as a solid waste incineration unit or January 1 after 

the first 3 consecutive calendar years after 2005 for which the 
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unit has an average annual fuel consumption of fossil fuel of 20 

percent or more.

(c) A certifying official of an owner or operator of any unit or 

other equipment may submit a petition (including any supporting 

documents) to the Administrator at any time for a determination 

concerning the applicability, under paragraphs (a) and (b) of 

this section, of the TR SO2 Group 1 Trading Program to the unit 

or other equipment.

(1) Petition content. The petition shall be in writing and 

include the identification of the unit or other equipment and 

the relevant facts about the unit or other equipment. The 

petition and any other documents provided to the Administrator 

in connection with the petition shall include the following 

certification statement, signed by the certifying official: “I 

am authorized to make this submission on behalf of the owners 

and operators of the unit or other equipment for which the 

submission is made. I certify under penalty of law that I have 

personally examined, and am familiar with, the statements and 

information submitted in this document and all its attachments. 

Based on my inquiry of those individuals with primary 

responsibility for obtaining the information, I certify that the 

statements and information are to the best of my knowledge and 

belief true, accurate, and complete. I am aware that there are 
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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.

(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 
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format prescribed by the Administrator, that the unit was 

permanently retired on a specified date and will comply with the 

requirements of paragraph (b) of this section.

(b) Special provisions. (1) A unit exempt under paragraph (a) of 

this section shall not emit any SO2, starting on the date that 

the exemption takes effect.

(2) For a period of 5 years from the date the records are 

created, the owners and operators of a unit exempt under 

paragraph (a) of this section shall retain, at the source that 

includes the unit, records demonstrating that the unit is 

permanently retired. The 5-year period for keeping records may 

be extended for cause, at any time before the end of the period, 

in writing by the Administrator. The owners and operators bear 

the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the 

designated representative of a unit exempt under paragraph (a) 

of this section shall comply with the requirements of the TR SO2

Group 1 Trading Program concerning all periods for which the 

exemption is not in effect, even if such requirements arise, or 

must be complied with, after the exemption takes effect.

(4) A unit exempt under paragraph (a) of this section shall lose 

its exemption on the first date on which the unit resumes 
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operation. Such unit shall be treated, for purposes of applying 

allocation, monitoring, reporting, and recordkeeping 

requirements under this subpart, as a unit that commences 

commercial operation on the first date on which the unit resumes 

operation.

§ 97.606 Standard requirements.

(a) Designated representative requirements. The owners and 

operators shall comply with the requirement to have a designated 

representative, and may have an alternate designated 

representative, in accordance with §§97.613 through 97.618.

(b) Emissions monitoring, reporting, and recordkeeping 

requirements. (1) The owners and operators, and the designated 

representative, of each TR SO2 Group 1 source and each TR SO2

Group 1 unit at the source shall comply with the monitoring, 

reporting, and recordkeeping requirements of §§97.630 through 

97.635.

(2) The emissions data determined in accordance with §§97.630 

through 97.635 shall be used to calculate allocations of TR SO2

Group 1 allowances under §§97.611(a)(2) and (b) and 97.612 and 

to determine compliance with the TR SO2 Group 1 emissions 

limitation and assurance provisions under paragraph (c) of this 

section, provided that, for each monitoring location from which 
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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:

(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
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(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 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 (as of the allowance 

transfer deadline 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 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 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) Two times the amount by which total SO2 emissions from all TR 

SO2 Group 1 units at TR SO2 Group 1 sources in the 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 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 one-year 

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 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 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 
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section for the control period starting on the later of January 

1, 2012 or the deadline for meeting the unit's monitor 

certification requirements under §97.630(b) and for each control 

period thereafter.

(4) Vintage of deducted allowances. A TR SO2 Group 1 allowance 

shall not be deducted, for compliance with the requirements 

under paragraphs (c)(1)(i) and (2)(i) through (iii) of this 

section, for a control period in a calendar year before the year 

for which the TR SO2 Group 1 allowance was allocated.

(5) Allowance Management System requirements. Each TR SO2 Group 1

allowance shall be held in, deducted from, or transferred into, 

out of, or between Allowance Management System accounts in 

accordance with this subpart.

(6) Limited authorization. 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:

(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 
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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 to the 

described monitoring and reporting (as added or changed, 

respectively) are already incorporated in such permit. This 
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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. 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.
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The administrative appeal procedures for decisions of the 

Administrator under the TR SO2 Group 1 Trading Program are set 

forth in part 78 of this chapter.

§ 97.609 [Reserved]

§ 97.610 State SO2 Group 1 trading budgets, new unit set-asides, 

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 Annual 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 189,335 11,360 ---

Maryland 30,120 602 ---

Michigan 194,537 3,696 195

Missouri 207,466 4,149 ---

New Jersey 5,574 111 ---

New York 20,497 389 20

North Carolina 136,881 10,814 137

Ohio 310,230 6,205 ---

Pennsylvania 278,651 5,573 ---

Tennessee 148,150 2,963 ---

Virginia 70,820 2,833 ---
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West Virginia 146,174 10,232 ---

Wisconsin 79,480 3,895 79

State

SO2 Annual Group 1 

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

Illinois 124,123 6,206 ---

Indiana 161,111 4,833 ---

Iowa 75,184 1,428 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 11,823 225 12

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’ one-year variability limits for the State SO2

Group 1 trading budgets for the control periods in 2012 and 

thereafter are as follows:
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State

One-year variability limits

for 2012 and 2013

One-year

variability limits

for 2014 and thereafter

Illinois 23,489 12,412

Indiana 28,542 16,111

Iowa 10,709 7,518

Kentucky 18,934 10,628

Maryland 3,012 2,820

Michigan 19,454 14,400

Missouri 20,747 16,594

New Jersey 1,115 1,115

New York 2,050 1,182

North Carolina 13,688 5,762

Ohio 31,023 13,708

Pennsylvania 27,865 11,202

Tennessee 14,815 5,883

Virginia 7,082 3,506

West Virginia 14,617 7,567

Wisconsin 7,948 4,013

§ 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 for 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 for a unit in such 

notice does not constitute a determination that the unit is not 

a TR SO2 Group 1 unit. 
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(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 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 for each TR SO2

Group 1 unit, in accordance with §97.612(a)(1) through (8), 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 
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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)(1)(i) 

of this section and shall be limited to addressing whether the 

calculations are in accordance with §97.612(a)(1) through (8) 

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)(1) through (8) 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, 
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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 

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 for each TR SO2 Group 1 unit in accordance with 

§97.612(a)(9) and (10) and §§97.606(b)(2) and 97.630 through 

97.635. By February 15 immediately after the promulgation of 
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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.

(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 for each TR SO2 Group 1

unit, in accordance with §97.612(b)(1) through (8), 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 
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calculations are in accordance with §97.612(b)(1) through (8) 

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)(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)(1) through (8) 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.
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(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 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 for each TR SO2 Group 1 unit in accordance with 

§97.612(b)(9) and (10) 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 
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(b)(2)(iv)(A) of this section, and the results of such 

calculations. 

(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 §52.38(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 paragraph (b) of this section 

and §97.612, or under a provision of a SIP revision approved 

under §52.38(d), (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 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 

§52.38(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 
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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, 2012; or

(B) The recipient is not located as of January 1 of the control 

period in the State from whose TR 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

§52.38(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 §52.38(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.
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(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 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) The Administrator will transfer the TR SO2 Group 1 allowances 

that are not recorded, or that are deducted, in accordance with 

paragraphs (c)(2) and (3) of this section to, for a recipient 

under paragraph (c)(1)(i) of this section, the new unit set-
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aside for the State from whose SO2 Group 1 trading budget the TR 

SO2 Group 1 allowances were allocated, or, for a recipient under 

paragraph (c)(1)(ii) of this paragraph, to the State’s new unit 

set-aside or Indian country new unit set-aside from which the TR 

SO2 Group 1 allowances were allocated, for the control period in 

the year of such transfer.

§ 97.612 TR SO2 Group 1 allowance allocations for new units.

(a) For each control period in 2012 and thereafter and for the 

TR SO2 Group 1 units in each State other than those located in 

Indian county, the Administrator will allocate TR SO2 Group 1

allowances to the TR SO2 Group 1 units described in paragraph 

(a)(1) of this section and in accordance with paragraphs (a)(2) 

through (9) of this section:

(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 

(whether zero or greater) 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 (whether 

zero or greater) of TR SO2 Group 1 allowances for such control 
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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 (whether 

zero or greater) 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 that operate during the 

control period immediately preceding such control period; or

(iv) TR SO2 Group 1 units under §97.611(c)(1)(ii) whose 

allocation of an amount (whether zero or greater) 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 setaside for the State for each such control period. Each such 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(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 
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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; 

(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 non-Indian country portion of 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 for each TR SO2 annual unit described in 

paragraph (a)(1) 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.
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(ii) The Administrator will adjust the allocation amount in 

paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through 

(9) 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 

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 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 

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 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.
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(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)(1) through (8) 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 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 (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 described in the notice of 

data availability required under §97.611(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 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.

(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 for each 

such TR SO2 Group 1 unit the 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 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 paragraph 

(a)(9) of this section for such control period, any unallocated 
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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) and (iv), of the amount of TR SO2 Group 1

allowances allocated for such control period to each TR SO2 Group 

1 unit eligible for such allocation.

(b) For each control period in 2012 and thereafter and for the 

TR SO2 Group 1 units located in Indian country in each State, the 

Administrator will allocate TR SO2 Group 1 allowances to the TR 
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SO2 Group 1 units described in paragraph (b)(1) of this section 

and in accordance with paragraphs (b)(2) through (9) of this 

section:

(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:

(i) TR SO2 Group 1 units that are not allocated an amount

(whether zero or greater) of TR SO2 Group 1 allowances in the 

notice of data availability issued under §97.611(a)(1); or

(ii) TR SO2 Group 1 units under §97.611(c)(1)(ii) whose 

allocation of an amount (whether zero or greater) 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).
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(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.

(4)(i) The allocation for each TR SO2 annual unit described in 

paragraph (b)(1) 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 

(9) 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 the State for such 

control period.
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(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 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)(1) through (8) for 

such control period to each TR SO2 Group 1 unit eligible for such 

allocation.
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(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 set-aside 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 described 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 
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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.

(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 

for 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.

(10) If, after completion of the procedures under paragraph 

(b)(9) 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) Allocate such unallocated TR SO2 Group 1 allowances to the 

new unit set-aside for the State for such control period; or 
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(ii) If the State has a SIP revision approved under §52.38(d), 

(e), or (f) of this chapter, include such unallocated TR SO2

Group 1 allowances in the portion of the State TR 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) and (iv), of the amount of TR SO2 Group 1

allowances allocated for such control period to each TR SO2 Group 

1 unit eligible for such allocation.

§ 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).
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(2) Upon and after receipt by the Administrator of a complete 

certificate of representation under §97.616:

(i) The designated representative shall be authorized and shall 

represent and, by his or her representations, actions, 

inactions, or submissions, legally bind each owner and operator 

of the source and each TR SO2 Group 1 unit at the source in all 

matters pertaining to the TR SO2 Group 1 Trading Program, 

notwithstanding any agreement between the designated 

representative and such owners and operators; and

(ii) The owners and operators of the source and each TR SO2 Group 

1 unit at the source shall be bound by any decision or order 

issued to the designated representative by the Administrator 

regarding the source or any such unit.

(b) Except as provided under §97.615, each TR SO2 Group 1 source 

may have one and only one alternate designated representative, 

who may act on behalf of the designated representative. The 

agreement by which the alternate designated representative is 

selected shall include a procedure for authorizing the alternate 

designated representative to act in lieu of the designated 

representative.

(1) The alternate designated representative shall be selected by 

an agreement binding on the owners and operators of the source 
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and all TR SO2 Group 1 units at the source and shall act in 

accordance with the certification statement in 

§97.616(a)(4)(iii).

(2) Upon and after receipt by the Administrator of a complete 

certificate of representation under §97.616, 

(i) The alternate designated representative shall be authorized; 

(ii) Any representation, action, inaction, or submission by the 

alternate designated representative shall be deemed to be a 

representation, action, 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.
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§ 97.614 Responsibilities of designated representative and 

alternate designated representative.

(a) Except as provided under §97.618 concerning delegation of 

authority to make submissions, each submission under the TR SO2

Group 1 Trading Program shall be made, signed, and certified by 

the designated representative or alternate designated 

representative for each TR SO2 Group 1 source and TR SO2 Group 1

unit for which the submission is made. Each such submission 

shall include the following certification statement by the 

designated representative or alternate designated 

representative: “I am authorized to make this submission on 

behalf of the owners and operators of the source or units for 

which the submission is made. I certify under penalty of law 

that I have personally examined, and am familiar with, the 

statements and information submitted in this document and all 

its attachments. Based on my inquiry of those individuals with 

primary responsibility for obtaining the information, I certify 

that the statements and information are to the best of my 

knowledge and belief true, accurate, and complete. I am aware 

that there are significant penalties for submitting false 

statements and information or omitting required statements and 

information, including the possibility of fine or imprisonment.”
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(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.

(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 
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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 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 
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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 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 
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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 MWe, rounded to the nearest 

tenth) of each generator served by each such unit, and actual or 

projected date of commencement of commercial operation and 

including 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.
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(2) The name, address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of the 

designated representative and any alternate designated 

representative.

(3) A list of the owners and operators of the TR SO2 Group 1

source and of each TR SO2 Group 1 unit at the source.

(4) The following certification statements by the designated 

representative and any alternate designated representative—

(i) “I certify that I was selected as the designated 

representative or alternate designated representative, as 

applicable, by an agreement binding on the owners and operators 

of the source and each TR SO2 Group 1 unit at the source.”

(ii) “I certify that I have all the necessary authority to carry 

out my duties and responsibilities under the TR SO2 Group 1

Trading Program on behalf of the owners and operators of the 

source and of each TR SO2 Group 1 unit at the source and that 

each such owner and operator shall be fully bound by my 

representations, actions, inactions, or submissions and by any 

decision or order issued to me by the Administrator regarding 

the source or unit.”
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(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 be submitted to the Administrator. The Administrator shall 
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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 designated representative, including private legal 
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disputes concerning the proceeds of TR SO2 Group 1 allowance 

transfers.

§ 97.618 Delegation by designated representative and alternate 

designated representative.

(a) A designated representative may delegate, to one or more 

natural persons, his or her authority to make an electronic 

submission to the Administrator provided for or required under 

this subpart.

(b) An alternate designated representative may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(c) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph (a) 

or (b) of this section, the designated representative or 

alternate designated representative, as appropriate, must submit 

to the Administrator a notice of delegation, in a format 

prescribed by the Administrator, that includes the following 

elements:
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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 97.618(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 
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an e-mail account and to notify the Administrator immediately of 

any change in my e-mail address unless all delegation of 

authority by me under 40 CFR 97.618 is terminated.”.

(d) A notice of delegation submitted under paragraph (c) of this 

section shall be effective, with regard to the designated 

representative or alternate designated representative identified 

in such notice, upon receipt of such notice by the Administrator 

and until receipt by the Administrator of a superseding notice 

of delegation submitted by such designated representative or 

alternate designated representative, as appropriate. The 

superseding notice of delegation may replace any previously 

identified agent, add a new agent, or eliminate entirely any 

delegation of authority.

(e) Any electronic submission covered by the certification in 

paragraph (c)(4)(i) of this section and made in accordance with 

a notice of delegation effective under paragraph (d) of this 

section shall be deemed to be an electronic submission by the 

designated representative or alternate designated representative 

submitting such notice of delegation.

§ 97.619 [Reserved]

§ 97.620 Establishment of compliance accounts, assurance 

accounts, and general accounts.
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(a) Compliance accounts. Upon receipt of a complete certificate 

of representation under §97.616, the Administrator will 

establish a compliance account for the TR SO2 Group 1 source for 

which the certificate of representation was submitted, unless 

the source already has a compliance account. The designated 

representative and any alternate designated representative of 

the source shall be the authorized account representative and 

the alternate authorized account representative respectively of 

the compliance account.

(b) Assurance accounts. As provided in §97.625(b)(3), the 

Administrator will establish assurance accounts for the owners 

and operators and States specified in the notice required under 

§97.625(b)(2)(iii)(B). 

(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. 
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(A) The authorized account representative and alternate 

authorized account representative shall be selected by an 

agreement binding on the persons who have an ownership interest 

with respect to TR SO2 Group 1 allowances held in the general 

account. 

(B) The agreement by which the alternate authorized account 

representative is selected shall include a procedure for 

authorizing the alternate authorized account representative to 

act in lieu of the authorized account representative.

(ii) A complete application for a general account shall include 

the following elements in a format prescribed by the 

Administrator:

(A) Name, mailing address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of the 

authorized account representative and any alternate authorized 

account representative;

(B) An identifying name for the general account;

(C) A list of all persons subject to a binding agreement for the 

authorized account representative and any alternate authorized 

account representative to represent their ownership interest 
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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.”

(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 
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Administrator shall not be under any obligation to review or 

evaluate the sufficiency of such documents, if submitted.

(2) Authorization of authorized account representative and 

alternate authorized account representative. (i) Upon receipt 

by the Administrator of a complete application for a general 

account under paragraph (b)(1) of this section, the 

Administrator will establish a general account for the person or 

persons for whom the application is submitted, and upon and 

after such receipt by the Administrator:

(A) The authorized account representative of the general account 

shall be authorized and shall represent and, by his or her 

representations, actions, inactions, or submissions, legally 

bind each person who has an ownership interest with respect to 

TR SO2 Group 1 allowances held in the general account in all 

matters pertaining to the TR SO2 Group 1 Trading Program, 

notwithstanding any agreement between the authorized account 

representative and such person. 

(B) Any alternate authorized account representative shall be 

authorized, and any representation, action, inaction, or 

submission by any alternate authorized account representative 

shall be deemed to be a representation, action, inaction, or 

submission by the authorized account representative.
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(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 

information are to the best of my knowledge and belief true,
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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.
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(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 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.
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(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 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 
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authorized account representative or any alternate authorized 

account representative or the finality of any decision or order 

by the Administrator under the TR SO2 Group 1 Trading Program.

(iii) The Administrator will not adjudicate any private legal 

dispute concerning the authorization or any representation, 

action, inaction, or submission of the authorized account 

representative or any alternate authorized account 

representative of a general account, including private legal 

disputes concerning the proceeds of TR SO2 Group 1 allowance 

transfers.

(5) Delegation by authorized account representative and 

alternate authorized account representative. (i) An authorized 

account representative of a general account may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(ii) An alternate authorized account representative of a general 

account may delegate, to one or more natural persons, his or her 

authority to make an electronic submission to the Administrator 

provided for or required under this subpart.

(iii) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph 
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(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 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 
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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 e-mail account and to notify the 

Administrator immediately of any change in my e-mail address 

unless all delegation of authority by me under 40 CFR 

97.620(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)(i) The authorized account representative or alternate 

authorized account representative of a general account may 

submit to the Administrator a request to close the account. 

Such request shall include a correctly submitted TR SO2 Group 1

allowance transfer under §97.622 for any TR SO2 Group 1

allowances in the account to one or more other Allowance 

Management System accounts.

(ii) If a general account has no TR SO2 Group 1 allowance 

transfers to or from the account for a 12-month period or longer 

and does not contain any TR SO2 Group 1 allowances, the 

Administrator may notify the authorized account representative 

for the account that the account will be closed after 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 
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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.

(d) 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. 

§ 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.
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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 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 §52.38(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.

(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.
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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 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 for the TR SO2 Group 1 units at the source in 

accordance with §97.611(a), or with a SIP revision approved 

under §52.38(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 for the TR SO2 Group 1 units at the source in 

accordance with §97.611(a), or with a SIP revision approved 

under §52.38(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 for the TR SO2 Group 1 units at the source in 
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accordance with §97.611(a), or with a SIP revision approved 

under §52.38(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 for 

the TR SO2 Group 1 units at the source in accordance with 

§97.611(a), or with a SIP revision approved under §52.38(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 for 

the TR SO2 Group 1 units at the source in accordance with 

§97.612(a), or with a SIP revision approved under §52.38(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 for 

the TR SO2 Group 1 units at the source in accordance with 
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§97.612(b) for the control period in the year of the applicable 

recordation deadline under this paragraph.

(i) By the date on which any allocation, other than an 

allocation described in paragraphs (a) through (h) of this 

section, of TR SO2 Group 1 allowances to a recipient is made by 

or submitted to the Administrator in accordance with §97.611 or 

§97.612 or with a SIP revision approved under §52.38(e) or (f)

of this chapter, the Administrator will record such allocation 

in the appropriate Allowance Management System account. 

(j) To the extent a SIP revision approved under §52.38(e) or (f)

of this chapter provides for one or more auctions, in lieu of 

allocation, of TR SO2 Group 1 allowances for a control period in 

a given year, the Administrator will record in the appropriate 

Allowance Management System account under such SIP revision the 

amount of TR SO2 Group 1 allowances purchased at such auctions by 

the deadline, specified in paragraphs (a) through (h) of this 

section, for recordation of an allocation for the control period 

in such year. 

(k) When recording the allocation or auction of TR SO2 Group 1

allowances for a TR SO2 Group 1 unit in an Allowance Management 

System account, the Administrator will assign each TR SO2 Group 1

allowance a unique identification number that will include 
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digits identifying the year of the control period for which the 

TR SO2 Group 1 allowance is allocated.

§ 97.622 Submission of TR SO2 Group 1 allowance transfers.

(a) An authorized account representative seeking recordation of 

a TR SO2 Group 1 allowance transfer shall submit the transfer to 

the Administrator. 

(b) A TR SO2 Group 1 allowance transfer shall be correctly 

submitted if: 

(1) The transfer includes the following elements, in a format 

prescribed by the Administrator:

(i) The account numbers established by the Administrator for 

both the transferor and transferee accounts;

(ii) The serial number of each TR SO2 Group 1 allowance that is 

in the transferor account and is to be transferred; and

(iii) The name and signature of the authorized account 

representative of the transferor account and the date signed; 

and

(2) When the Administrator attempts to record the transfer, the 

transferor account includes each TR SO2 Group 1 allowance 

identified by serial number in the transfer. 
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§ 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.

(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, 
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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

(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 
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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 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 
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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 amount of TR SO2 Group 1

allowances, allocated for the control period in the immediately 
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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 only if the TR SO2 Group 1

allowances: 

(1) Were allocated for such control period or a control period 

in a prior 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 under paragraph 

(b)(3) of this section, as of the deadline established in 

paragraph (b)(5) of this section. 

(b) Deductions for compliance. The Administrator will deduct TR 

SO2 Group 1 allowances available under paragraph (a) of this 
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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, separately for each State, the total SO2 emissions 

from all TR SO2 Group 1 units at TR SO2 Group 1 sources in the 

State during the control period in the year before the year of 

this calculation deadline and the amount, if any, by which such 

total 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 identified in such 

notice as having TR SO2 Group 1 units with total SO2 emissions 

exceeding the State assurance level for a control period in a 

given year, as described in §97.606(c)(2)(iii):
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(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 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 each common designated representative (authorized as of the 

allowance transfer deadline for such control period) for a group 

of one or more TR SO2 Group 1 sources and units in the State and 

for such control period, 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, 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 

calculation formula in §97.606(c)(2)(i) and will promulgate a 

notice of data availability of the results of these 

calculations. 
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(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 accepting or 
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rejecting any objections submitted in accordance with paragraph 

(b)(2)(iii)(A) of this section.

(3) For any State identified 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 identified, 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 having a common 

designated representative (as of the allowance transfer deadline 

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 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 
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and operators are required to hold with regard to such sources, 

units and 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 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 States 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 involved, provided that such litigation 

under part 78 of this chapter, or the proceeding under part 78 
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of this chapter that resulted in the decision appealed in such 

litigation under section 307 of the Clean Air Act, was initiated 

no later than 30 days after promulgation of such notice required 

in paragraph (b)(2)(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 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 (b)(6)(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 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 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, 
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and State under paragraph (b)(3) of this section, a total amount 

of TR SO2 Group 1 allowances 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, or recorded under paragraph 

(b)(6)(iii)(B) 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 such control period or a control period in a prior year. 

§ 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.
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The owners and operators, and to the extent applicable, the 

designated representative, of a TR SO2 Group 1 unit, shall comply 

with the monitoring, recordkeeping, and reporting requirements 

as provided in this subpart and subparts F and G of part 75 of 

this chapter. For purposes of applying such requirements, the 

definitions in §97.602 and in §72.2 of this chapter shall apply, 

the terms “affected unit,” “designated representative,” and 

“continuous emission monitoring system” (or “CEMS”) in part 75 

of this chapter shall be deemed to refer to the terms “TR SO2

Group 1 unit,“ “designated representative,” and “continuous 

emission monitoring system” (or “CEMS”) respectively as defined 

in §97.602, and the term “newly affected unit” shall be deemed 

to mean “newly affected TR SO2 Group 1 unit”. The owner or 

operator of a unit that is not a TR SO2 Group 1 unit but that is 

monitored under §75.16(b)(2) of this chapter shall comply with 

the same monitoring, recordkeeping, and reporting requirements 

as a TR SO2 Group 1 unit.

(a) Requirements for installation, certification, and data 

accounting. The owner or operator of each TR SO2 Group 1 unit 

shall:

(1) Install all monitoring systems required under this subpart 

for monitoring SO2 mass emissions and individual unit heat input 
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(including all systems required to monitor SO2 concentration, 

stack gas moisture content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as applicable, in accordance 

with §§75.11 and 75.16 of this chapter);

(2) Successfully complete all certification tests required under 

§97.631 and meet all other requirements of this subpart and part 

75 of this chapter applicable to the monitoring systems under 

paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the 

monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) of 

this section, the owner or operator shall meet the monitoring 

system certification and other requirements of paragraphs (a)(1) 

and (2) of this section on or before the following dates. The 

owner or operator shall record, report, and quality-assure the 

data from the monitoring systems under paragraph (a)(1) of this 

section on and after the following dates.

(1) For the owner or operator of a TR SO2 Group 1 unit that 

commences commercial operation before July 1, 2011, by January 

1, 2012.
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(2) For the owner or operator of a TR SO2 Group 1 unit that 

commences commercial operation on or after July 1, 2011, by the 

later of the following dates:

(i) January 1, 2012; or

(ii) 180 calendar days after the date on which the unit 

commences commercial operation.

(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
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(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 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
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emissions to the atmosphere without accounting for all such 

emissions in accordance with the applicable provisions of this 

subpart and part 75 of this chapter.

(3) No owner or operator of a TR SO2 Group 1 unit shall disrupt 

the continuous emission monitoring system, any portion thereof, 

or any other approved emission monitoring method, and thereby 

avoid monitoring and recording SO2 mass emissions discharged into 

the atmosphere or heat input, except for periods of 

recertification or periods when calibration, quality assurance 

testing, or maintenance is performed in accordance with the 

applicable provisions of this subpart and part 75 of this 

chapter.

(4) No owner or operator of a TR SO2 Group 1 unit shall retire or 

permanently discontinue use of the continuous emission 

monitoring system, any component thereof, or any other approved 

monitoring system under this subpart, except under any one of 

the following circumstances:

(i) During the period that the unit is covered by an exemption 

under §97.605 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit 
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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.

(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
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(2) The applicable quality-assurance and quality-control 

requirements of § 75.21 of this chapter and appendices B and D 

to part 75 of this chapter are fully met for the certified 

monitoring system described in paragraph (a)(1) of this section.

(b) The recertification provisions of this section shall apply 

to a monitoring system under § 97.630(a)(1) exempt from initial 

certification requirements under paragraph (a) of this section.

(c) [Reserved]

(d) Except as provided in paragraph (a) of this section, the 

owner or operator of a TR SO2 Group 1 unit shall comply with the 

following initial certification and recertification procedures, 

for a continuous monitoring system (i.e., a continuous emission 

monitoring system and an excepted monitoring system under 

appendix D to part 75 of this chapter) under §97.630(a)(1). The 

owner or operator of a unit that qualifies to use the low mass 

emissions excepted monitoring methodology under §75.19 of this 

chapter or that qualifies to use an alternative monitoring 

system under subpart E of part 75 of this chapter shall comply 

with the procedures in paragraph (e) or (f) of this section 

respectively.
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(1) Requirements for initial certification. The owner or 

operator shall ensure that each continuous monitoring system 

under §97.630(a)(1) (including the automated data acquisition 

and handling system) successfully completes all of the initial 

certification testing required under §75.20 of this chapter by 

the applicable deadline in §97.630(b). In addition, whenever 

the owner or operator installs a monitoring system to meet the 

requirements of this subpart in a location where no such 

monitoring system was previously installed, initial 

certification in accordance with §75.20 of this chapter is 

required.

(2) Requirements for recertification. Whenever the owner or 

operator makes a replacement, modification, or change in any 

certified continuous emission monitoring system under 

§97.630(a)(1) that may significantly affect the ability of the 

system to accurately measure or record SO2 mass emissions or heat 

input rate or to meet the quality-assurance and quality-control 

requirements of §75.21 of this chapter or appendix B to part 75 

of this chapter, the owner or operator shall recertify the 

monitoring system in accordance with §75.20(b) of this chapter. 

Furthermore, whenever the owner or operator makes a replacement, 

modification, or change to the flue gas handling system or the 
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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 
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certification by issuing a notice of disapproval within 120 days 

of the date of receipt of the complete certification application 

by the Administrator.

(iv) Certification application approval process. The 

Administrator will issue a written notice of approval or 

disapproval of the certification application to the owner or 

operator within 120 days of receipt of the complete 

certification application under paragraph (d)(3)(ii) of this 

section. In the event the Administrator does not issue such a 

notice within such 120-day period, each monitoring system that 

meets the applicable performance requirements of part 75 of this 

chapter and is included in the certification application will be 

deemed certified for use under the TR SO2 Group 1 Trading 

Program.

(A) Approval notice. If the certification application is 

complete and shows that each monitoring system meets the 

applicable performance requirements of part 75 of this chapter, 

then the Administrator will issue a written notice of approval 

of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification 

application is not complete, then the Administrator will issue a 
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written notice of incompleteness that sets a reasonable date by 

which the designated representative must submit the additional 

information required to complete the certification application. 

If the designated representative does not comply with the notice 

of incompleteness by the specified date, then the Administrator 

may issue a notice of disapproval under paragraph (d)(3)(iv)(C) 

of this section. The 120-day review period specified in 

paragraph (d)(3) of this section shall not begin before receipt 

of a complete certification application.

(C) Disapproval notice. If the certification application shows 

that any monitoring system does not meet the performance 

requirements of part 75 of this chapter or if the certification 

application is incomplete and the requirement for disapproval 

under paragraph (d)(3)(iv)(B) of this section is met, then the 

Administrator will issue a written notice of disapproval of the 

certification application. Upon issuance of such notice of 

disapproval, the provisional certification is invalidated by the 

Administrator and the data measured and recorded by each 

uncertified monitoring system shall not be considered valid 

quality-assured data beginning with the date and hour of 

provisional certification (as defined under §75.20(a)(3) of this 

chapter). 
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(D) Audit decertification. The Administrator may issue a notice 

of disapproval of the certification status of a monitor in 

accordance with §97.632(b).

(v) Procedures for loss of certification. If the Administrator 

issues a notice of disapproval of a certification application 

under paragraph (d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under paragraph 

(d)(3)(iv)(D) of this section, then:

(A) The owner or operator shall substitute the following values, 

for each disapproved monitoring system, for each hour of unit 

operation during the period of invalid data specified under 

§75.20(a)(4)(iii), §75.20(g)(7), or §75.21(e) of this chapter 

and continuing until the applicable date and hour specified 

under §75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved SO2 pollutant concentration monitor and 

disapproved flow monitor, respectively, the maximum potential 

concentration of SO2 and the maximum potential flow rate, as 

defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 

of this chapter.

(2) For a disapproved moisture monitoring system and disapproved 
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diluent gas monitoring system, respectively, the minimum 

potential moisture percentage and either the maximum potential 

CO2 concentration or the minimum potential O2 concentration (as 

applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 

of appendix A to part 75 of this chapter.

(3) For a disapproved fuel flowmeter system, the maximum 

potential fuel flow rate, as defined in section 2.4.2.1 of 

appendix D to part 75 of this chapter.

(B) The designated representative shall submit a notification of 

certification retest dates and a new certification application 

in accordance with paragraphs (d)(3)(i) and (ii) of this 

section.

(C) The owner or operator shall repeat all certification tests 

or other requirements that were failed by the monitoring system, 

as indicated in the Administrator's notice of disapproval, no 

later than 30 unit operating days after the date of issuance of 

the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low 

mass emissions (LME) excepted methodology under §75.19 of this 

chapter shall meet the applicable certification and 
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recertification requirements in §§75.19(a)(2) and 75.20(h) of 

this chapter. If the owner or operator of such a unit elects to 

certify a fuel flowmeter system for heat input determination, 

the owner or operator shall also meet the certification and 

recertification requirements in §75.20(g) of this chapter.

(f) The designated representative of each unit for which the 

owner or operator intends to use an alternative monitoring 

system approved by the Administrator under subpart E of part 75 

of this chapter shall comply with the applicable notification 

and application procedures of §75.20(f) of this chapter.

§ 97.632 Monitoring system out-of-control periods.

(a) General provisions. Whenever any monitoring system fails to 

meet the quality-assurance and quality-control requirements or 

data validation requirements of part 75 of this chapter, data 

shall be substituted using the applicable missing data 

procedures in subpart D or appendix D to part 75 of this 

chapter.

(b) Audit decertification. Whenever both an audit of a 

monitoring system and a review of the initial certification or 

recertification application reveal that any monitoring system 

should not have been certified or recertified because it did not 
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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. 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.
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§ 97.634 Recordkeeping and reporting.

(a) General provisions. The designated representative shall 

comply with all recordkeeping and reporting requirements in this 

section, the applicable recordkeeping and reporting requirements 

in subparts F and G of part 75 of this chapter, and the 

requirements of §97.614(a).

(b) Monitoring plans. The owner or operator of a TR SO2 Group 1

unit shall comply with requirements of §75.62 of this chapter. 

(c) Certification applications. The designated representative 

shall submit an application to the Administrator within 45 days 

after completing all initial certification or recertification 

tests required under §97.631, including the information required 

under §75.63 of this chapter.

(d) Quarterly reports. The designated representative shall 

submit quarterly reports, as follows:

(1) The designated representative shall report the SO2 mass 

emissions data and heat input data for the TR SO2 Group 1 unit, 

in an electronic quarterly report in a format prescribed by the 

Administrator, for each calendar quarter beginning with:
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(i) For a unit that commences commercial operation before July 

1, 2011, the calendar quarter covering January 1, 2012 through 

March 31, 2012;

(ii) For a unit that commences commercial operation on or after 

July 1, 2011, the calendar quarter corresponding to the earlier 

of the date of provisional certification or the applicable 

deadline for initial certification under §97.630(b), unless that 

quarter is the third or fourth quarter of 2011, in which case 

reporting shall 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 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
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mass emission data, heat input data, and other information 

required by this subpart.

(4) The Administrator may review and conduct independent audits 

of any quarterly report in order to determine whether the 

quarterly report meets the requirements of this subpart and part 

75 of this chapter, including the requirement to use substitute 

data. 

(i) The Administrator will notify the designated representative 

of any determination that the quarterly report fails to meet any 

such requirements and specify in such notification any 

corrections that the Administrator believes are necessary to 

make through resubmission of the quarterly report and a 

reasonable time period within which the designated 

representative must respond. Upon request by the designated 

representative, the Administrator may specify reasonable 

extensions of such time period. Within the time period 

(including any such extensions) specified by the Administrator, 

the designated representative shall resubmit the quarterly 

report with the corrections specified by the Administrator, 

except to the extent the designated representative provides 

information demonstrating that a specified correction is not 

necessary because the quarterly report already meets the 
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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 
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assurance/quality control program under appendix B to part 75 of 

this chapter and the substitute data values do not 

systematically underestimate SO2 emissions.

§ 97.635 Petitions for alternatives to monitoring, 

recordkeeping, or reporting requirements.

(a) The designated representative of a TR SO2 Group 1 unit may 

submit a petition under §75.66 of this chapter to the 

Administrator, requesting approval to apply an alternative to 

any requirement of §§97.630 through 97.634 or paragraph (5)(i) 

or (ii) of the definition of “owner’s share” in §97.602. 

(b) A petition submitted under paragraph (a) of this section 

shall include sufficient information for the evaluation of the 

petition, including, at a minimum, the following information:

(i) Identification of each unit and source covered by the 

petition;

(ii) A detailed explanation of why the proposed alternative is 

being suggested in lieu of the requirement;

(iii) A description and diagram of any equipment and procedures 

used in the proposed alternative;
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(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.

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.
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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 for new units.

97.713 Authorization of designated representative and alternate 

designated representative.

97.714 Responsibilities of designated representative and 

alternate designated representative.

97.715 Changing designated representative and alternate 

designated representative; changes in owners and operators.

97.716 Certificate of representation.

97.717 Objections concerning designated representative and 

alternate designated representative.
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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.

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.
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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 §52.38 of this chapter, as a means of mitigating 

interstate transport of fine particulates and nitrogen oxides.

§ 97.702 Definitions.

The terms used in this subpart shall have the meanings set forth 

in this section as follows:

Acid Rain Program means a 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.
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Administrator means the Administrator of the United States 

Environmental Protection Agency or the Director of the Clean Air 

Markets Division (or its successor) of the United States 

Environmental Protection Agency, the Administrator's duly 

authorized representative under this subpart.

Allocate or allocation means, with regard to TR SO2 Group 2 

allowances, the determination by the Administrator, 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(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;

(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 
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being allocated an amount (i.e., zero) of TR SO2 Group 2 

allowances. 

Allowable SO2 emission rate means, with regard to 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.

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 
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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, with regard to 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, in which are held TR SO2

Group 2 allowances available for 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. 
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Authorized account representative means, with regard to a 

general account, the natural person who is authorized, in 

accordance with this subpart, to transfer and otherwise dispose 

of TR SO2 Group 2 allowances held in the general account and, 

with regard to a TR SO2 Group 2 source’s compliance account, the 

designated representative of the source.

Automated data acquisition and handling system or DAHS means the 

component of the continuous emission monitoring system, or other 

emissions monitoring system approved for use under this subpart, 

designed to interpret and convert individual output signals from 

pollutant concentration monitors, flow monitors, diluent gas 

monitors, and other component parts of the monitoring system to 

produce a continuous record of the measured parameters in the 

measurement units required by this subpart. 

Biomass means—

(1) Any organic material grown for the purpose of being 

converted to energy;

(2) Any organic byproduct of agriculture that can be converted 

into energy; or

(3) Any material that can be converted into energy and is 

nonmerchantable for other purposes, that is segregated from 
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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 

vice-president or the corporation in charge of a principal 

business function or any other person who performs similar 

policy- or decision-making functions for the corporation;

(2) For a partnership or sole proprietorship, a general partner 

or the proprietor respectively; or

(3) For a local government entity or State, federal, or other 

public agency, a principal executive officer or ranking elected 

official.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq. 

Coal means “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. 
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Cogeneration unit means a stationary, fossil-fuel-fired boiler 

or stationary, fossil-fuel-fired combustion turbine—

(1) Operating as part of a cogeneration system; and

(2) Producing on an annual average basis during the later of 

2005 or the 12-month period starting on the date that the unit 

first produces electricity and during each calendar year after 

the later of 2005 or the calendar year in which the unit first 

produces electricity—

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less than 5 percent of total 

energy output; and

(B) Useful power that, when added to one-half of useful thermal 

energy produced, is not less 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;
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(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:

(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
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(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 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 
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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 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, 
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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 a designated 

representative where 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.

Common designated representative’s assurance level means, with 

regard to a specific common designated representative and a 

State and control period in a given year for which the State 

assurance level is exceeded as described in §97.706(c)(2)(iii), 

the common designated representative’s share of the State SO2

Group 2 trading budget with the one-year variability limit for 

the State for such control period. 

Common designated representative’s share means, with regard to a 

specific common designated representative:

(1) With regard to a total amount of SO2 emissions from all TR 

SO2 Group 2 units in a State during a control period in a given 

year, the total tonnage of SO2 emissions during such control 

period from a group of one or more TR SO2 Group 2 units located 
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in the State and having the common designated representative as 

of the allowance transfer deadline for such control period; 

(2) With regard to a State SO2 Group 2 trading budget for a 

control period in a given year, 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 

having the common designated representative as of the allowance 

transfer deadline 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 to the Administrator for 

recordation in the compliance accounts for such TR SO2 Group 2 

units in accordance with the TR SO2 Group 2 allowance auction 

provisions in a SIP revision approved by the Administrator under 

§52.38(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 

one-year 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, a control period in a given year, the 

unit shall be treated, solely for purposes of this definition, 
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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 0.87 (if the unit is

a boiler combusting any amount of coal or coal-derived fuel 

during such control period), 0.14 (if the unit is a simple 

combustion turbine during such control period), 0.70 (if the 

unit is a combined cycle turbine during such control period), 

0.46 (if the unit is a boiler combusting only fuel oil or 

natural gas during such control period), or 0.71 (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.

Compliance account means an Allowance Management System account, 

established by the Administrator for a TR SO2 Group 2 source 

under this subpart, in which any TR SO2 Group 2 allowance 

allocations for the TR SO2 Group 2 units at the source are 

recorded and in which are held any TR SO2 Group 2 allowances 

available for use for a control period in a given year in 

complying with the source's TR SO2 Group 2 emissions limitation 

in accordance with §§97.706 and 97.724. 
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Continuous emission monitoring system or CEMS means the 

equipment required under this subpart to sample, analyze, 

measure, and provide, by means of readings recorded at least 

once every 15 minutes and using an automated data acquisition 

and handling system (DAHS), a permanent record of SO2 emissions, 

stack gas volumetric flow rate, stack gas moisture content, and 

O2 or CO2 concentration (as applicable), in a manner consistent 

with part 75 of this chapter and §§97.730 through 97.735. The 

following systems are the principal types of continuous emission 

monitoring systems:

(1) A flow monitoring system, consisting of a stack flow rate 

monitor and an automated data acquisition and handling system 

and providing a permanent, continuous record of stack gas 

volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A SO2 monitoring system, consisting of a SO2 pollutant 

concentration monitor and an automated data acquisition and 

handling system and providing a permanent, continuous record of 

SO2 emissions, in parts per million (ppm);

(3) A moisture monitoring system, as defined in §75.11(b)(2) of 

this chapter and providing a permanent, continuous record of the 

stack gas moisture content, in percent H2O;
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(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, with regard to a TR SO2 Group 2 

source and each TR SO2 Group 2 unit at the source, the natural 

person who is authorized by the owners and operators of the 

source and all such units at the source, in accordance with this 

subpart, to represent and legally bind each owner and operator 

in matters pertaining to the TR SO2 Group 2 Trading Program. If 

the TR SO2 Group 2 source is also subject to the Acid Rain 

Program, TR NOX Annual Trading Program, or TR NOX Ozone Season 

Trading Program, then this natural person shall be the same 
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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 
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(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.

Fuel oil means “fuel oil” as defined in §72.2 of this chapter.

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 
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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, with regard to 

a specific fuel, the amount of heat input attributed to the fuel 

(in mmBtu) divided by the unit operating time (in hr) during 

which the unit combusts the fuel.

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, as defined in 18 U.S.C. 1151:

(1) All land within the limits of any Indian reservation under 

the jurisdiction of the United States Government, 

notwithstanding the issuance of any patent, and, including 

rights-of-way running through the reservation;

(2) All dependent Indian communities within the borders of the 

United States whether within the original or subsequently 

acquired territory thereof, and whether within or without the 

limits of a state; and 
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(3) All Indian allotments, the Indian titles to which have not 

been extinguished, including rights-of-way running through the 

same.

Life-of-the-unit, firm power contractual arrangement means a 

unit participation power sales agreement under which a utility 

or industrial customer reserves, or is entitled to receive, a 

specified amount or percentage of nameplate capacity and 

associated energy generated by any specified unit and pays its 

proportional amount of such unit's total costs, pursuant to a 

contract:

(1) For the life of the unit;

(2) For a cumulative term of no less than 30 years, including 

contracts that permit an election for early termination; or

(3) For a period no less than 25 years or 70 percent of the 

economic useful life of the unit determined as of the time the 

unit is built, with option rights to purchase or release some 

portion of the nameplate capacity and associated energy 

generated by the unit at the end of the period.

Maximum design heat input means, 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
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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.

Natural gas means “natural gas” as defined in §72.2 of this 

chapter.
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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, with regard to 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, with regard to a TR SO2 Group 2 source or a TR SO2

Group 2 unit at a source respectively, any of the following 

persons:

(1) Any holder of any portion of the legal or equitable title in 

a TR SO2 Group 2 unit at the source or the TR SO2 Group 2 unit;

(2) Any holder of a leasehold interest in a TR SO2 Group 2 unit 

at the source or the TR SO2 Group 2 unit, provided that, unless 

expressly provided for in a leasehold agreement, “owner” shall 

not include a passive lessor, or a person who has an equitable

interest through such lessor, whose rental payments are not 
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based (either directly or indirectly) on the revenues or income 

from such TR SO2 Group 2 unit; and

(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.
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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.

Reference method means any direct test method of sampling and 

analyzing for an air pollutant as specified in §75.22 of this 

chapter.

Replacement, replace, or replaced means, with regard to a unit, 

the demolishing of a unit, or the permanent retirement and 

permanent disabling of a unit, and the construction of another 

unit (the replacement unit) to be used instead of the demolished 

or retired unit (the replaced unit).

Sequential use of energy means:

(1) For a topping-cycle unit, the use of reject heat from 

electricity production in a useful thermal energy application or 

process; or

(2) For a bottoming-cycle unit, the use of reject heat from 

useful thermal energy application or process in electricity 

production.
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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-fuelfired 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 SO2 Group 

2 Trading Program pursuant to §52.38(a),(c), (g), (h), and (i)

of this chapter and, when used to refer to a geographic area, 

includes Indian country located within the borders of such 

State.

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
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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 §52.37(a) of this 

chapter (including such a program that is revised in a SIP 

revision approved by the Administrator under §52.37(a)(3) or (4) 

of this chapter) or with a SIP revision approved by the 

Administrator under §52.37(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 §52.37(b) of this 

chapter (including such a program that is revised by a State in 

a SIP revision approved by the Administrator under §52.37(b)(3) 

or (4) of this chapter) or with a SIP revision approved by the 

Administrator under §52.37(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 
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approved by the Administrator under §52.38(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 assurance provisions. 

TR SO2 Group 2 allowances held or hold TR SO2 Group 2 allowances

means the TR SO2 Group 2 allowances treated as included in an 

Allowance Management System account as of a specified point in 

time because at that time they:

(1) Have been recorded by the Administrator in the account or 

transferred into the account by a correctly submitted, but not 

yet recorded, TR SO2 Group 2 allowance transfer in accordance 

with this subpart; and

(2) Have not been transferred out of the account by a correctly 

submitted, but not yet recorded, TR SO2 Group 2 allowance 

transfer in accordance with this subpart.
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TR SO2 Group 2 emissions limitation means, for a TR SO2 Group 2 

source, the tonnage of SO2 emissions authorized in a control 

period by the TR SO2 Group 2 allowances available for deduction 

for the source under §97.724(a) for such control period.

TR SO2 Group 2 source means a source that includes one or more TR 

SO2 Group 2 units.

TR SO2 Group 2 Trading Program means a multi-state SO2 air 

pollution control and emission reduction program established by 

the Administrator in accordance with this subpart and 

§52.38(a)and (c) of this chapter (including such a program that 

is revised by a State in a SIP revision approved by the 

Administrator under §52.38(g) or (h) of this chapter) or with a 

SIP revision approved by the Administrator under §52.38(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, 

fossil-fuel-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 
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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;

(2) Used in a heating application (e.g., space heating or 

domestic hot water heating); or
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(3) Used in a space cooling application (i.e., in an absorption 

chiller).

Utility power distribution system means the portion of an 

electricity grid owned or operated by a utility and dedicated to 

delivering electricity to customers.

§ 97.703 Measurements, abbreviations, and acronyms.

Measurements, abbreviations, and acronyms used in this subpart 

are defined as follows:

Btu—British thermal unit

CO2—carbon dioxide

H2O—water

hr—hour

kW—kilowatt electrical

kWh—kilowatt hour

lb—pound

mmBtu—million Btu

MWe—megawatt electrical
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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 (including Indian country 

located 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, 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 SO2
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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 (including Indian country located 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), (b)(2)(i), or 

(b)(2)(ii) of this section shall not be a TR SO2 Group 2 unit:

(1)(i) Any unit:

(A) Qualifying as a cogeneration unit 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; 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 a unit qualifies as a cogeneration unit throughout the 

later of 2005 or the 12-month period starting on the date the 

unit first produces electricity and meets the requirements of 

paragraphs (b)(1)(i) of this section for at least one calendar 

year, but subsequently no longer meets such qualification and 

requirements, the unit shall become a TR SO2 Group 2 unit 

starting on the earlier of January 1 after the first calendar 

year during which the unit first no longer qualifies as a 

cogeneration unit or January 1 after the first calendar year 

during which the unit no longer meets the requirements of 

paragraph (b)(1)(i)(B) of this section.

(2)(i) Any unit:

(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; 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).
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(ii) If a unit qualifies 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 meets the 

requirements of paragraph (b)(2)(i) of this section for at least 

3 consecutive calendar years, but subsequently no longer meets 

such qualification and requirements, the unit shall become a TR 

SO2 Group 2 unit starting on the earlier of January 1 after the 

first calendar year during which the unit first no longer 

qualifies as a solid waste incineration unit or January 1 after 

the first 3 consecutive calendar years after 2005 for which the 

unit has an average annual fuel consumption of fossil fuel of 20 

percent or more.

(c) A certifying official of an owner or operator of any unit or 

other equipment may submit a petition (including any supporting 

documents) to the Administrator at any time for a determination 

concerning the applicability, under paragraphs (a) and (b) of 

this section, of the TR SO2 Group 2 Trading Program to the unit 

or other equipment.

(1) Petition content. The petition shall be in writing and 

include the identification of the unit or other equipment and 

the relevant facts about the unit or other equipment. The 

petition and any other documents provided to the Administrator 

in connection with the petition shall include the following 
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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.
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§ 97.705 Retired unit exemption.

(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, 
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in writing by the Administrator. The owners and operators bear 

the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the 

designated representative of a unit exempt under paragraph (a) 

of this section shall comply with the requirements of the TR SO2

Group 2 Trading Program concerning all periods for which the 

exemption is not in effect, even if such requirements arise, or 

must be complied with, after the exemption takes effect.

(4) A unit exempt under paragraph (a) of this section shall lose 

its exemption on the first date on which the unit resumes 

operation. Such unit shall be treated, for purposes of applying 

allocation, monitoring, reporting, and recordkeeping 

requirements under this subpart, as a unit that commences 

commercial operation on the first date on which the unit resumes 

operation.

§ 97.706 Standard requirements.

(a) Designated representative requirements. The owners and 

operators shall comply with the requirement to have a designated 

representative, and may have an alternate designated 

representative, in accordance with §§97.713 through 97.718.
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(b) Emissions monitoring, reporting, and recordkeeping 

requirements. (1) The owners and operators, and the designated 

representative, of each TR SO2 Group 2 source and each TR SO2

Group 2 unit at the source shall comply with the monitoring, 

reporting, and recordkeeping requirements of §§97.730 through 

97.735.

(2) The emissions data determined in accordance with §§97.730 

through 97.735 shall be used to calculate allocations of TR SO2

Group 2 allowances under §§97.711(a)(2) and (b) and 97.712 and 

to determine compliance with the TR SO2 Group 2 emissions 

limitation and assurance provisions under paragraph (c) of this 

section, provided that, for each monitoring location from which 

mass emissions are reported, the mass emissions amount used in 

calculating such allocations and determining such compliance 

shall be the mass emissions amount for the monitoring location 

determined in accordance with §§97.730 through 97.735 and 

rounded to the nearest ton, with any fraction of a ton less than 

0.50 being deemed to be zero.

(c) SO2 emissions requirements. (1) TR SO2 Group 2 emissions 

limitation. (i) As of the allowance transfer deadline for a 

control period 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 
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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:

(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 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 
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having a common designated representative (as of the allowance 

transfer deadline 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 the product (rounded to the nearest whole 

number), as determined by the Administrator in accordance with 

§97.725(b), of multiplying—

(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 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) Two times the amount by which total SO2 emissions from all TR 

SO2 Group 2 units at TR SO2 Group 2 sources in the State for such 

control period exceed the State assurance level. 
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(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 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 one-year 

variability limit under §97.710(b).

(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 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 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 
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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 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 deducted allowances. A TR SO2 Group 2 allowance 

shall not be deducted, for compliance with the requirements 

under paragraphs (c)(1)(i) and (2)(i) through (iii) of this 

section, for a control period in a calendar year before the year 

for which the TR SO2 Group 2 allowance was allocated.
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(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:

(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.
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(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 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 
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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.

(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. This requirement does not 

change, create an exemption from, or or otherwise affect the 
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responsible official submission requirements under a title V operating 

permit program in parts 70 and 71 of this chapter. 

(f) Liability. (1) Any provision of the TR SO2 Group 2 Trading 

Program that applies to a TR SO2 Group 2 source or the designated 

representative of a TR SO2 Group 2 source shall also apply to the 

owners and operators of such source and of the TR SO2 Group 2 

units at the source.

(2) Any provision of the TR SO2 Group 2 Trading Program that 

applies to a TR SO2 Group 2 unit or the designated representative 

of a TR SO2 Group 2 unit shall also apply to the owners and 

operators of such unit.

(g) Effect on other authorities. No provision of the TR SO2

Group 2 Trading Program or exemption under §97.705 shall be 

construed as exempting or excluding the owners and operators, 

and the designated representative, of a TR SO2 Group 2 source or 

TR SO2 Group 2 unit from compliance with any other provision of 

the applicable, approved State implementation plan, a federally 

enforceable permit, or the Clean Air Act.

§ 97.707 Computation of time.

(a) Unless otherwise stated, any time period scheduled, under 

the TR SO2 Group 2 Trading Program, to begin on the occurrence of 

an act or event shall begin on the day the act or event occurs. 
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(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.

§ 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 Annual Group 2 New unit set- Indian country new 
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trading budget 

(tons)*

for 2012 and 2013

aside (tons)

for 2012 and 

2013

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 1,684 89

Texas 243,954 11,954 244

State

SO2 Annual 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

South Carolina 88,620 1,684 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’ one-year variability limits for the State SO2

Group 2 trading budgets for the control periods in 2012 and 

thereafter are as follows:
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State

One-year variability limits

for 2012 and 2013

One-year

variability limits

for 2014 and thereafter

Alabama 21,603 21,326

Georgia 15,853 9,523

Kansas 4,153 4,153

Minnesota 4,198 4,198

Nebraska 6,505 6,505

South Carolina 8,862 8,862

Texas 24,395 24,395

§ 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 for a unit in such notice 

does not constitute a determination that the unit is a TR SO2

Group 2 unit, and not providing an allocation for 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 
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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 for each TR SO2

Group 2 unit, in accordance with §97.712(a)(1) through (8), 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. 
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(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 are in accordance with §97.712(a)(1) through (8) 

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)(1) through (8) 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 

(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 
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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 for each TR SO2 Group 2 unit in accordance with 

§97.712(a)(9) and (10) 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)(1)(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)(1)(iv)(A) of this section, and the results of such 

calculations.

(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 for each TR SO2 Group 2 

unit, in accordance with §97.712(b)(1) through (8), 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 are in accordance with §97.712(b)(1) through (8) 

and §§97.706(b)(2) and 97.730 through 97.735. 
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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 

§97.712(b)(1) through (8) 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 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 
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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)(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 for each TR SO2 Group 2 unit in accordance with 

§97.712(b)(9) and (10) 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 

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. 
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(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 §52.38(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 paragraph (b) of this section and 

§97.712, or under a provision of a SIP revision approved 

§52.38(g), (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 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 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 

§52.38(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 
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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 TR 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 

§52.38(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 

§52.38(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. 

(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.
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(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) The Administrator will transfer the TR SO2 Group 2 allowances 

that are not recorded, or that are deducted, in accordance with 

paragraphs (c)(2) and (3) of this section to, for a recipient 

under paragraph (c)(1)(i) of this section, the new unit set-
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aside for the State from whose SO2 Group 2 trading budget the TR 

SO2 Group 2 allowances were allocated, or, for a recipient under 

paragraph (c)(1)(ii) of this paragraph, to the State’s new unit 

set-aside or Indian country new unit set-aside from which the TR 

SO2 Group 2 allowances were allocated, for the control period in 

the year of such transfer.

§ 97.712 TR SO2 Group 2 allowance allocations for new units.

(a) For each control period in 2012 and thereafter and for the 

TR SO2 Group 2 units in each State other than those located in 

Indian county, the Administrator will allocate TR SO2 Group 2 

allowances to the TR SO2 Group 2 units described in paragraph 

(a)(1) of this section and in accordance with paragraphs (a)(2) 

through (9) of this section:

(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 

(whether zero or greater) 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 (whether 

zero or greater) of TR SO2 Group 2 allowances for such control 
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period in the notice of data 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 (whether 

zero or greater) 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) TR SO2 Group 2 units under §97.711(c)(1)(ii) whose 

allocation of an amount (whether zero or greater) 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 setaside for the State for each such control period. Each such 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(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 
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allocation of TR SO2 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 non-Indian country portion of 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 for each TR SO2 annual unit described in 

paragraph (a)(1) 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.
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(ii) The Administrator will adjust the allocation amount in 

paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through 

(9) 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 (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 

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 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 

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 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.
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(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)(1) through (8) 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 setaside 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 described in the notice of 

data availability required under §97.711(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 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 amount of TR SO2 Group 2 

allowances determined for each such TR SO2 Group 2 unit under 

paragraph (a)(9)(i) of this section.

(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 for 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 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 paragraph 

(a)(9) of this section for such control period, any unallocated 
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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 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) and (iv), of the amount of TR SO2 Group 2 

allowances allocated for such control period to each TR SO2 Group 

2 unit eligible for such allocation.

(b) For each control period in 2012 and thereafter and for the 

TR SO2 Group 2 units located in Indian country in each State, the 

Administrator will allocate TR SO2 Group 2 allowances to the TR 
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SO2 Group 2 units described in paragraph (b)(1) of this section 

and in accordance with paragraphs (b)(2) through (9) of this 

section:

(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 

(whether zero or greater) of TR SO2 Group 2 allowances in the 

notice of data availability issued under §97.711(a)(1); or

(ii) TR SO2 Group 2 units under §97.711(c)(1)(ii) whose 

allocation of an amount (whether zero or greater) 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).
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(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 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 for each TR SO2 annual unit described in 

paragraph (b)(1) 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 

(9) 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 the State for such 

control period.
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(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 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)(1) through (8) for 

such control period to each TR SO2 Group 2 unit eligible for such 

allocation.
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(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 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 (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 described 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 
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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.

(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 

for 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 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 paragraph 

(b)(9) 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) Allocate such unallocated TR SO2 Group 2 allowances to the 

new unit set-aside for the State for such control period; or 
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(ii) If the State has a SIP revision approved under §52.38(g), 

(h), or (i) of this chapter, include such unallocated TR SO2

Group 2 allowances in the portion of the State TR 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) and (iv), of the amount of TR SO2 Group 2 

allowances allocated for such control period to each TR SO2 Group 

2 unit eligible for such allocation.

§ 97.713 Authorization of designated representative and 

alternate designated representative.

(a) Except as provided under §97.715, each TR SO2 Group 2 source, 

including all TR SO2 Group 2 units at the source, shall have one 

and only one designated representative, with regard to all 

matters under the TR SO2 Group 2 Trading Program.

(1) The designated representative shall be selected by an 

agreement binding on the owners and operators of the source and 

all TR SO2 Group 2 units at the source and shall act in 

accordance with the certification statement in 

§97.716(a)(4)(iii).
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(2) Upon and after receipt by the Administrator of a complete 

certificate of representation under §97.716:

(i) The designated representative shall be authorized and shall 

represent and, by his or her representations, actions, 

inactions, or submissions, legally bind each owner and operator 

of the source and each TR SO2 Group 2 unit at the source in all 

matters pertaining to the TR SO2 Group 2 Trading Program, 

notwithstanding any agreement between the designated 

representative and such owners and operators; and

(ii) The owners and operators of the source and each TR SO2 Group 

2 unit at the source shall be bound by any decision or order 

issued to the designated representative by the Administrator 

regarding the source or any such unit.

(b) Except as provided under §97.715, each TR SO2 Group 2 source 

may have one and only one alternate designated representative, 

who may act on behalf of the designated representative. The 

agreement by which the alternate designated representative is 

selected shall include a procedure for authorizing the alternate 

designated representative to act in lieu of the designated 

representative.

(1) The alternate designated representative shall be selected by 

an agreement binding on the owners and operators of the source 
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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.”
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(b) The Administrator will accept or act on a submission made 

for a TR SO2 Group 2 source or a TR SO2 Group 2 unit only if the 

submission has been made, signed, and certified in accordance 

with paragraph (a) of this section and §97.718.

§ 97.715 Changing designated representative and alternate 

designated representative; changes in owners and operators; 

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 
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submissions by the previous alternate designated representative 

before the time and date when the Administrator receives the 

superseding certificate of representation shall be binding on 

the new alternate designated representative, the designated 

representative, and the owners and operators of the TR SO2 Group 

2 source and the TR SO2 Group 2 units at the source.

(c) Changes in owners and operators. (1) In the event an owner 

or operator of a TR SO2 Group 2 source or a TR SO2 Group 2 unit 

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 
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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 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 
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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:

(1) Identification of the TR SO2 Group 2 source, and each TR SO2

Group 2 unit at the source, for which the certificate of 

representation is submitted, including source name, source 

category and NAICS code (or, in the absence of a NAICS code, an 

equivalent code), State, plant code, county, latitude and 

longitude, unit identification number and type, identification 

number and nameplate capacity (in MWe, rounded to the nearest 

tenth) of each generator served by each such unit, and actual or 

projected date of commencement of commercial operation and 

including 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.
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(2) The name, address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of the 

designated representative and any alternate designated 

representative.

(3) A list of the owners and operators of the TR SO2 Group 2 

source and of each TR SO2 Group 2 unit at the source.

(4) The following certification statements by the designated 

representative and any alternate designated representative—

(i) “I certify that I was selected as the designated 

representative or alternate designated representative, as 

applicable, by an agreement binding on the owners and operators 

of the source and each TR SO2 Group 2 unit at the source.”

(ii) “I certify that I have all the necessary authority to carry 

out my duties and responsibilities under the TR SO2 Group 2 

Trading Program on behalf of the owners and operators of the 

source and of each TR SO2 Group 2 unit at the source and that 

each such owner and operator shall be fully bound by my 

representations, actions, inactions, or submissions and by any 

decision or order issued to me by the Administrator regarding 

the source or unit.”
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(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 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 
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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 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 
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disputes concerning the proceeds of TR SO2 Group 2 allowance 

transfers.

§ 97.718 Delegation by designated representative and alternate 

designated representative.

(a) A designated representative may delegate, to one or more 

natural persons, his or her authority to make an electronic 

submission to the Administrator provided for or required under 

this subpart.

(b) An alternate designated representative may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(c) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph (a) 

or (b) of this section, the designated representative or 

alternate designated representative, as appropriate, must submit 

to the Administrator a notice of delegation, in a format 

prescribed by the Administrator, that includes the following 

elements:
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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 
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an e-mail account and to notify the Administrator immediately of 

any change in my e-mail address unless all delegation of 

authority by me under 40 CFR 97.718 is terminated.”.

(d) A notice of delegation submitted under paragraph (c) of this 

section shall be effective, with regard to the designated 

representative or alternate designated representative identified 

in such notice, upon receipt of such notice by the Administrator 

and until receipt by the Administrator of a superseding notice 

of delegation submitted by such designated representative or 

alternate designated representative, as appropriate. The 

superseding notice of delegation may replace any previously 

identified agent, add a new agent, or eliminate entirely any 

delegation of authority.

(e) Any electronic submission covered by the certification in 

paragraph (c)(4)(i) of this section and made in accordance with 

a notice of delegation effective under paragraph (d) of this 

section shall be deemed to be an electronic submission by the 

designated representative or alternate designated representative 

submitting such notice of delegation.

§ 97.719 [Reserved]

§ 97.720 Establishment of compliance accounts, assurance 

accounts, and general accounts.
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(a) Compliance accounts. Upon receipt of a complete certificate 

of representation under §97.716, the Administrator will 

establish a compliance account for the TR SO2 Group 2 source for 

which the certificate of representation was submitted, unless 

the source already has a compliance account. The designated 

representative and any alternate designated representative of 

the source shall be the authorized account representative and 

the alternate authorized account representative respectively of 

the compliance account.

(b) Assurance accounts. As provided in §97.725(b)(3), the 

Administrator will establish assurance accounts for the owners 

and operators and States specified in the notice required under 

§97.725(b)(2)(iii)(B). 

(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. 
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(A) The authorized account representative and alternate 

authorized account representative shall be selected by an 

agreement binding on the persons who have an ownership interest 

with respect to TR SO2 Group 2 allowances held in the general 

account. 

(B) The agreement by which the alternate authorized account 

representative is selected shall include a procedure for 

authorizing the alternate authorized account representative to 

act in lieu of the authorized account representative.

(ii) A complete application for a general account shall include 

the following elements in a format prescribed by the 

Administrator:

(A) Name, mailing address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of the 

authorized account representative and any alternate authorized 

account representative;

(B) An identifying name for the general account;

(C) A list of all persons subject to a binding agreement for the 

authorized account representative and any alternate authorized 

account representative to represent their ownership interest 
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with respect to the TR SO2 Group 2 allowances held in the general 

account;

(D) The following certification statement by the authorized 

account representative and any alternate authorized account 

representative: “I certify that I was selected as the authorized 

account representative or the alternate authorized account 

representative, as applicable, by an agreement that is binding 

on all persons who have an ownership interest with respect to TR 

SO2 Group 2 allowances held in the general account. I certify 

that I have all the necessary authority to carry out my duties 

and responsibilities under the TR SO2 Group 2 Trading Program on 

behalf of such persons and that each such person shall be fully 

bound by my representations, actions, inactions, or submissions 

and by any 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 
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Administrator shall not be under any obligation to review or 

evaluate the sufficiency of such documents, if submitted.

(2) Authorization of authorized account representative and 

alternate authorized account representative. (i) Upon receipt 

by the Administrator of a complete application for a general 

account under paragraph (b)(1) of this section, the 

Administrator will establish a general account for the person or 

persons for whom the application is submitted, and upon and 

after such receipt by the Administrator:

(A) The authorized account representative of the general account 

shall be authorized and shall represent and, by his or her 

representations, actions, inactions, or submissions, legally 

bind each person who has an ownership interest with respect to 

TR SO2 Group 2 allowances held in the general account in all 

matters pertaining to the TR SO2 Group 2 Trading Program, 

notwithstanding any agreement between the authorized account 

representative and such person. 

(B) Any alternate authorized account representative shall be 

authorized, and any representation, action, inaction, or 

submission by any alternate authorized account representative 

shall be deemed to be a representation, action, inaction, or 

submission by the authorized account representative.
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(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 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, 
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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 2 allowances in the general account.
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(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 
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authorized account representative or any alternate authorized 

account representative or the finality of any decision or order 

by the Administrator under the TR SO2 Group 2 Trading Program.

(iii) The Administrator will not adjudicate any private legal 

dispute concerning the authorization or any representation, 

action, inaction, or submission of the authorized account 

representative or any alternate authorized account 

representative of a general account, including private legal 

disputes concerning the proceeds of TR SO2 Group 2 allowance 

transfers.

(5) Delegation by authorized account representative and 

alternate authorized account representative. (i) An authorized 

account representative of a general account may delegate, to one 

or more natural persons, his or her authority to make an 

electronic submission to the Administrator provided for or 

required under this subpart.

(ii) An alternate authorized account representative of a general 

account may delegate, to one or more natural persons, his or her 

authority to make an electronic submission to the Administrator 

provided for or required under this subpart.

(iii) In order to delegate authority to make an electronic 

submission to the Administrator in accordance with paragraph 
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(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 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 
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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 delegation under 40 CFR 97.720(c)(5)(iv), I 

agree to maintain an e-mail account and to notify the 

Administrator immediately of any change in my e-mail address 

unless all delegation of authority by me under 40 CFR 

97.720(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)(i) The authorized account representative or alternate 

authorized account representative of a general account may 

submit to the Administrator a request to close the account. 

Such request shall include a correctly submitted TR SO2 Group 2 

allowance transfer under §97.722 for any TR SO2 Group 2 

allowances in the account to one or more other Allowance 

Management System accounts.

(ii) If a general account has no TR SO2 Group 2 allowance 

transfers to or from the account for a 12-month period or longer 

and does not contain any TR SO2 Group 2 allowances, the 

Administrator may notify the authorized account representative 

for the account that the account will be closed 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 
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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.

(d) 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 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.
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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 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 §52.38(g)(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 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.
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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 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 for the TR SO2 Group 2 units at the source in 

accordance with §97.711(a), or with a SIP revision approved 

under §52.38(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 for the TR SO2 Group 2 units at the source in 

accordance with §97.711(a), or with a SIP revision approved 

under §52.38(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 for the TR SO2 Group 2 units at the source in 
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accordance with §97.711(a), or with a SIP revision approved 

under §52.38(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 for 

the TR SO2 Group 2 units at the source in accordance with 

§97.711(a), or with a SIP revision approved under §52.38(h) and

(i) 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 2 source's 

compliance account the TR SO2 Group 2 allowances allocated for 

the TR SO2 Group 2 units at the source in accordance with 

§97.712(a), or with a SIP revision approved under §52.38(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 for 

the TR SO2 Group 2 units at the source in accordance with 
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§97.712(b) for the control period in the year of the applicable 

recordation deadline under this paragraph.

(i) By the date on which any allocation, other than an 

allocation described in paragraphs (a) through (h) of this 

section, of TR SO2 Group 2 allowances to a recipient is made by 

or submitted to the Administrator in accordance with §97.711 or 

§97.712 or with a SIP revision approved under §52.38(h) or (i)

of this chapter, the Administrator will record such allocation 

in the appropriate Allowance Management System account. 

(j) To the extent a SIP revision approved under §52.38(h) or (i)

of this chapter provides for one or more auctions, in lieu of 

allocation, of TR SO2 Group 2 allowances for a control period in 

a given year, the Administrator will record in the appropriate 

Allowance Management System account under such SIP revision the 

amount of TR SO2 Group 2 allowances purchased at such auctions by 

the deadline, specified in paragraphs (a) through (h) of this 

section, for recordation of an allocation for the control period 

in such year. 

(k) When recording the allocation or auction of TR SO2 Group 2 

allowances for a TR SO2 Group 2 unit in an Allowance Management 

System account, the Administrator will assign each TR SO2 Group 2 

allowance a unique identification number that will include 
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digits identifying the year of the control period for which the 

TR SO2 Group 2 allowance is allocated.

§ 97.722 Submission of TR SO2 Group 2 allowance transfers.

(a) An authorized account representative seeking recordation of 

a TR SO2 Group 2 allowance transfer shall submit the transfer to 

the Administrator. 

(b) A TR SO2 Group 2 allowance transfer shall be correctly 

submitted if: 

(1) The transfer includes the following elements, in a format 

prescribed by the Administrator:

(i) The account numbers established by the Administrator for 

both the transferor and transferee accounts;

(ii) The serial number of each TR SO2 Group 2 allowance that is 

in the transferor account and is to be transferred; and

(iii) The name and signature of the authorized account 

representative of the transferor account and the date signed; 

and

(2) When the Administrator attempts to record the transfer, the 

transferor account includes each TR SO2 Group 2 allowance 

identified by serial number in the transfer. 
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§ 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 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, 
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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:

(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 
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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 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 
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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 in a year in which the TR SO2 Group 2 source 

has excess emissions, the Administrator will deduct from the 

source's compliance account an amount of TR SO2 Group 2 

allowances, allocated for the control period in the immediately 
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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 only if the TR SO2 Group 2 

allowances: 

(1) Were allocated for such control period or a control period 

in a prior 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 under paragraph 

(b)(3) of this section, as of the deadline established in 

paragraph (b)(5) of this section. 

(b) Deductions for compliance. The Administrator will deduct TR 

SO2 Group 2 allowances available under paragraph (a) of this 
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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, separately for each State, the total SO2 emissions 

from all TR SO2 Group 2 units at TR SO2 Group 2 sources in the 

State during the control period in the year before the year of 

this calculation deadline and the amount, if any, by which such 

total 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 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):
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(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 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 each common designated representative (authorized as of the 

allowance transfer deadline for such control period) for a group 

of one or more TR SO2 Group 2 sources and units in the State and 

for such control period, 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, 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 

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. 
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(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 accepting or 
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rejecting any objections submitted in accordance with paragraph 

(b)(2)(iii)(A) of this section.

(3) For any State identified 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 identified, 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 having a common 

designated representative (as of the allowance transfer deadline 

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 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 
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and operators are required to hold with regard to such sources, 

units and 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 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 States 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 involved, provided that such litigation 

under part 78 of this chapter, or the proceeding under part 78 
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of this chapter that resulted in the decision appealed in such 

litigation under section 307 of the Clean Air Act, was initiated 

no later than 30 days after promulgation of such notice required 

in paragraph (b)(2)(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 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 (b)(6)(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 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 under paragraph (b)(3) of this section. The owners’ and 

operaters’ 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, 
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and State under paragraph (b)(3) of this section, a total amount 

of TR SO2 Group 2 allowances 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, or recorded under paragraph 

(b)(6)(iii)(B) 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 such control period or a control period in a prior year. 

§ 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.
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The owners and operators, and to the extent applicable, the 

designated representative, of a TR SO2 Group 2 unit, shall comply 

with the monitoring, recordkeeping, and reporting requirements 

as provided in this subpart and subparts F and G of part 75 of 

this chapter. For purposes of applying such requirements, the 

definitions in §97.702 and in §72.2 of this chapter shall apply, 

the terms “affected unit,” “designated representative,” and 

“continuous emission monitoring system” (or “CEMS”) in part 75 

of this chapter shall be deemed to refer to the terms “TR SO2

Group 2 unit,“ “designated representative,” and “continuous 

emission monitoring system” (or “CEMS”) respectively as defined 

in §97.702, and the term “newly affected unit” shall be deemed 

to mean “newly affected TR SO2 Group 2 unit”. The owner or 

operator of a unit that is not a TR SO2 Group 2 unit but that is 

monitored under §75.16(b)(2) of this chapter shall comply with 

the same monitoring, recordkeeping, and reporting requirements 

as a TR SO2 Group 2 unit.

(a) Requirements for installation, certification, and data 

accounting. The owner or operator of each TR SO2 Group 2 unit 

shall:

(1) Install all monitoring systems required under this subpart 

for monitoring SO2 mass emissions and individual unit heat input 
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(including all systems required to monitor SO2 concentration, 

stack gas moisture content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as applicable, in accordance 

with §§75.11 and 75.16 of this chapter);

(2) Successfully complete all certification tests required under 

§97.731 and meet all other requirements of this subpart and part 

75 of this chapter applicable to the monitoring systems under 

paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the 

monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. Except as provided in paragraph (e) of 

this section, the owner or operator shall meet the monitoring 

system certification and other requirements of paragraphs (a)(1) 

and (2) of this section on or before the following dates. The 

owner or operator shall record, report, and quality-assure the 

data from the monitoring systems under paragraph (a)(1) of this 

section on and after the following dates.

(1) For the owner or operator of a TR SO2 Group 2 unit that 

commences commercial operation before July 1, 2011, by January 

1, 2012.
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(2) For the owner or operator of a TR SO2 Group 2 unit that 

commences commercial operation on or after July 1, 2011, by the 

later of the following dates:

(i) January 1, 2012; or

(ii) 180 calendar days after the date on which the unit 

commences commercial operation.

(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
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(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 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
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emissions to the atmosphere without accounting for all such 

emissions in accordance with the applicable provisions of this 

subpart and part 75 of this chapter.

(3) No owner or operator of a TR SO2 Group 2 unit shall disrupt 

the continuous emission monitoring system, any portion thereof, 

or any other approved emission monitoring method, and thereby 

avoid monitoring and recording SO2 mass emissions discharged into 

the atmosphere or heat input, except for periods of 

recertification or periods when calibration, quality assurance 

testing, or maintenance is performed in accordance with the 

applicable provisions of this subpart and part 75 of this 

chapter.

(4) No owner or operator of a TR SO2 Group 2 unit shall retire or 

permanently discontinue use of the continuous emission 

monitoring system, any component thereof, or any other approved 

monitoring system under this subpart, except under any one of 

the following circumstances:

(i) During the period that the unit is covered by an exemption 

under §97.705 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit 
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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.

(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
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(2) The applicable quality-assurance and quality-control 

requirements of § 75.21 of this chapter and appendices B and D 

to part 75 of this chapter are fully met for the certified 

monitoring system described in paragraph (a)(1) of this section.

(b) The recertification provisions of this section shall apply 

to a monitoring system under § 97.730(a)(1) exempt from initial 

certification requirements under paragraph (a) of this section.

(c) [Reserved]

(d) Except as provided in paragraph (a) of this section, the 

owner or operator of a TR SO2 Group 2 unit shall comply with the 

following initial certification and recertification procedures, 

for a continuous monitoring system (i.e., a continuous emission 

monitoring system and an excepted monitoring system under 

appendix D to part 75 of this chapter) under §97.730(a)(1). The 

owner or operator of a unit that qualifies to use the low mass 

emissions excepted monitoring methodology under §75.19 of this 

chapter or that qualifies to use an alternative monitoring 

system under subpart E of part 75 of this chapter shall comply 

with the procedures in paragraph (e) or (f) of this section 

respectively.
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(1) Requirements for initial certification. The owner or 

operator shall ensure that each continuous monitoring system 

under §97.730(a)(1) (including the automated data acquisition 

and handling system) successfully completes all of the initial 

certification testing required under §75.20 of this chapter by 

the applicable deadline in §97.730(b). In addition, whenever 

the owner or operator installs a monitoring system to meet the 

requirements of this subpart in a location where no such 

monitoring system was previously installed, initial 

certification in accordance with §75.20 of this chapter is 

required.

(2) Requirements for recertification. Whenever the owner or 

operator makes a replacement, modification, or change in any 

certified continuous emission monitoring system under 

§97.730(a)(1) that may significantly affect the ability of the 

system to accurately measure or record SO2 mass emissions or heat 

input rate or to meet the quality-assurance and quality-control 

requirements of §75.21 of this chapter or appendix B to part 75 

of this chapter, the owner or operator shall recertify the 

monitoring system in accordance with §75.20(b) of this chapter. 

Furthermore, whenever the owner or operator makes a replacement, 

modification, or change to the flue gas handling system or the 
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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 
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certification by issuing a notice of disapproval within 120 days 

of the date of receipt of the complete certification application 

by the Administrator.

(iv) Certification application approval process. The 

Administrator will issue a written notice of approval or 

disapproval of the certification application to the owner or 

operator within 120 days of receipt of the complete 

certification application under paragraph (d)(3)(ii) of this 

section. In the event the Administrator does not issue such a 

notice within such 120-day period, each monitoring system that 

meets the applicable performance requirements of part 75 of this 

chapter and is included in the certification application will be 

deemed certified for use under the TR SO2 Group 2 Trading 

Program.

(A) Approval notice. If the certification application is 

complete and shows that each monitoring system meets the 

applicable performance requirements of part 75 of this chapter, 

then the Administrator will issue a written notice of approval 

of the certification application within 120 days of receipt.

(B) Incomplete application notice. If the certification 

application is not complete, then the Administrator will issue a 
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written notice of incompleteness that sets a reasonable date by 

which the designated representative must submit the additional 

information required to complete the certification application. 

If the designated representative does not comply with the notice 

of incompleteness by the specified date, then the Administrator 

may issue a notice of disapproval under paragraph (d)(3)(iv)(C) 

of this section. The 120-day review period specified in 

paragraph (d)(3) of this section shall not begin before receipt 

of a complete certification application.

(C) Disapproval notice. If the certification application shows 

that any monitoring system does not meet the performance 

requirements of part 75 of this chapter or if the certification 

application is incomplete and the requirement for disapproval 

under paragraph (d)(3)(iv)(B) of this section is met, then the 

Administrator will issue a written notice of disapproval of the 

certification application. Upon issuance of such notice of 

disapproval, the provisional certification is invalidated by the 

Administrator and the data measured and recorded by each 

uncertified monitoring system shall not be considered valid 

quality-assured data beginning with the date and hour of 

provisional certification (as defined under §75.20(a)(3) of this 

chapter). 
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(D) Audit decertification. The Administrator may issue a notice 

of disapproval of the certification status of a monitor in 

accordance with §97.732(b).

(v) Procedures for loss of certification. If the Administrator 

issues a notice of disapproval of a certification application 

under paragraph (d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under paragraph 

(d)(3)(iv)(D) of this section, then:

(A) The owner or operator shall substitute the following values, 

for each disapproved monitoring system, for each hour of unit 

operation during the period of invalid data specified under 

§75.20(a)(4)(iii), §75.20(g)(7), or §75.21(e) of this chapter 

and continuing until the applicable date and hour specified 

under §75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved SO2 pollutant concentration monitor and 

disapproved flow monitor, respectively, the maximum potential 

concentration of SO2 and the maximum potential flow rate, as 

defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 

of this chapter.

(2) For a disapproved moisture monitoring system and disapproved 
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diluent gas monitoring system, respectively, the minimum 

potential moisture percentage and either the maximum potential 

CO2 concentration or the minimum potential O2 concentration (as 

applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 

of appendix A to part 75 of this chapter.

(3) For a disapproved fuel flowmeter system, the maximum 

potential fuel flow rate, as defined in section 2.4.2.1 of 

appendix D to part 75 of this chapter.

(B) The designated representative shall submit a notification of 

certification retest dates and a new certification application 

in accordance with paragraphs (d)(3)(i) and (ii) of this 

section.

(C) The owner or operator shall repeat all certification tests 

or other requirements that were failed by the monitoring system, 

as indicated in the Administrator's notice of disapproval, no 

later than 30 unit operating days after the date of issuance of 

the notice of disapproval.

(e) The owner or operator of a unit qualified to use the low 

mass emissions (LME) excepted methodology under §75.19 of this 

chapter shall meet the applicable certification and 
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recertification requirements in §§75.19(a)(2) and 75.20(h) of 

this chapter. If the owner or operator of such a unit elects to 

certify a fuel flowmeter system for heat input determination, 

the owner or operator shall also meet the certification and 

recertification requirements in §75.20(g) of this chapter.

(f) The designated representative of each unit for which the 

owner or operator intends to use an alternative monitoring 

system approved by the Administrator under subpart E of part 75 

of this chapter shall comply with the applicable notification 

and application procedures of §75.20(f) of this chapter.

§ 97.732 Monitoring system out-of-control periods.

(a) General provisions. Whenever any monitoring system fails to 

meet the quality-assurance and quality-control requirements or 

data validation requirements of part 75 of this chapter, data 

shall be substituted using the applicable missing data 

procedures in subpart D or appendix D to part 75 of this 

chapter.

(b) Audit decertification. Whenever both an audit of a 

monitoring system and a review of the initial certification or 

recertification application reveal that any monitoring system 

should not have been certified or recertified because it did not 
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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 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.
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§ 97.734 Recordkeeping and reporting.

(a) General provisions. The designated representative shall 

comply with all recordkeeping and reporting requirements in this 

section, the applicable recordkeeping and reporting requirements 

in subparts F and G of part 75 of this chapter, and the 

requirements of §97.714(a).

(b) Monitoring plans. The owner or operator of a TR SO2 Group 2 

unit shall comply with requirements of §75.62 of this chapter. 

(c) Certification applications. The designated representative 

shall submit an application to the Administrator within 45 days 

after completing all initial certification or recertification 

tests required under §97.731, including the information required 

under §75.63 of this chapter.

(d) Quarterly reports. The designated representative shall 

submit quarterly reports, as follows:

(1) The designated representative shall report the SO2 mass 

emissions data and heat input data for the TR SO2 Group 2 unit, 

in an electronic quarterly report in a format prescribed by the 

Administrator, for each calendar quarter beginning with:
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(i) For a unit that commences commercial operation before July 

1, 2011, the calendar quarter covering January 1, 2012 through 

March 31, 2012;

(ii) For a unit that commences commercial operation on or after 

July 1, 2011, the calendar quarter corresponding to the earlier 

of the date of provisional certification or the applicable 

deadline for initial certification under §97.730(b), unless that 

quarter is the third or fourth quarter of 2011, in which case 

reporting shall 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 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 
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required by this subpart.

(4) The Administrator may review and conduct independent audits 

of any quarterly report in order to determine whether the 

quarterly report meets the requirements of this subpart and part 

75 of this chapter, including the requirement to use substitute 

data. 

(i) The Administrator will notify the designated representative 

of any determination that the quarterly report fails to meet any 

such requirements and specify in such notification any 

corrections that the Administrator believes are necessary to 

make through resubmission of the quarterly report and a 

reasonable time period within which the designated 

representative must respond. Upon request by the designated 

representative, the Administrator may specify reasonable 

extensions of such time period. Within the time period 

(including any such extensions) specified by the Administrator, 

the designated representative shall resubmit the quarterly 

report with the corrections specified by the Administrator, 

except to the extent the designated representative provides 

information demonstrating that a specified correction is not 

necessary because the quarterly report already meets the 
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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 
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assurance/quality control program under appendix B to part 75 of 

this chapter and the substitute data values do not 

systematically underestimate SO2 emissions.

§ 97.735 Petitions for alternatives to monitoring, 

recordkeeping, or reporting requirements.

(a) The designated representative of a TR SO2 Group 2 unit may 

submit a petition under §75.66 of this chapter to the 

Administrator, requesting approval to apply an alternative to 

any requirement of §§97.730 through 97.734 or paragraph (5)(i) 

or (ii) of the definition of “owner’s share” in §97.702. 

(b) A petition submitted under paragraph (a) of this section 

shall include sufficient information for the evaluation of the 

petition, including, at a minimum, the following information:

(i) Identification of each unit and source covered by the 

petition;

(ii) A detailed explanation of why the proposed alternative is 

being suggested in lieu of the requirement;

(iii) A description and diagram of any equipment and procedures 

used in the proposed alternative;
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(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.